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	Quarter	Site	Title	Description
05000313/FIN-2013503-01	2012Q4	Arkansas Nuclear	Senior emergency planner falsely submitted documents that showed a postaccident sampling system drill and an environmental monitoring drill were conducted.	Based on the results of this investigation, one apparent violation was identified and is being considered for escalated enforcement action in accordance with the NRC Enforcement Policy. On January 12, 2012, the Arkansas Nuclear One Emergency Preparedness Manager notified the NRC resident inspector and regional emergency preparedness inspectors that a senior emergency planner had apparently falsified documents related to emergency preparedness drills conducted in December 2011. Specifically, the senior emergency planner falsely submitted documents that showed a postaccident sampling system drill and an environmental monitoring drill were conducted in 2011. Further investigation by Arkansas Nuclear One determined that these two drills were also falsified in December 2010 and several other required surveillances were also falsified by the senior emergency planner. The NRC investigation substantiated the above falsifications as described in the enclosed Factual Summary. These drills are required to be performed annually by the site emergency plan and maintained for inspection by the NRC. The NRC requires records of licensee activities to be complete and accurate in all material respects in order for the NRC to be able to perform its regulatory function. This information is material to the NRC because it provides assurance that the licensee has performed periodic drills to develop and maintain key emergency response organization skills and has adequately maintained facilities to support an emergency response. The circumstances surrounding these apparent violations, the significance of the issues, and the need for lasting and effective corrective action were discussed with members of your staff at the inspection exit meeting on February 21, 2013. In addition, since you identified the violation and based on our understanding of your corrective action, a civil penalty may not be warranted in accordance with Section 2.3.4 of the Enforcement Policy. The final decision will be based on your confirming on the license docket that the corrective actions previously described to the staff have been or are being taken. In lieu of a PEC, you may also request Alternative Dispute Resolution (ADR) with the NRC in an attempt to resolve this issue. ADR is a general term encompassing various techniques for resolving conflicts using a third party neutral. The technique that the NRC has decided to employ is mediation. Mediation is a voluntary, informal process in which a trained neutral (the mediator ) works with parties to help them reach resolution. If the parties agree to use ADR, they select a mutually agreeable neutral mediator who has no stake in the outcome and no power to make decisions. Mediation gives parties an opportunity to discuss issues, clear up misunderstandings, be creative, find areas of agreement, and reach a final resolution of the issues. Additional information concerning the NRC\\\'s program can be obtained at http://www.nrc.gov/about-nrc/regulatory/enforcement/adr.html. The Institute on Conflict Resolution (ICR) at Cornell University has agreed to facilitate the NRC\\\'s program as a neutral third party. Please contact ICR at 877-733-9415 within 10 days of the date of this letter if you are interested in pursuing resolution of this issue through ADR. In addition, please be advised that the number and characterization of apparent violations described in the enclosed inspection report may change as a result of further NRC review. You will be advised by separate correspondence of the results of our deliberations on this matter.
05000327/FIN-2012005-06	2012Q4	Sequoyah	Failure to Submit a Technical Specifications Required Report	The NRC identified a Severity Level IV non-cited violation of 10 CFR 50.36(c)(5) for failure to submit the Technical Specification (TS) required U1R18 Steam Generator report within 180 days after the initial entry into Mode 4 following completion of an inspection performed in accordance with the Specification 6.8.4.k, Steam Generator (SG) Program. The licensee entered this into their CAP as PER 648658 and as a corrective action submitted the report on December 17th 2012 to the NRC. The inspectors concluded that the failure of the licensee to submit a TS required report was a performance deficiency. The inspectors evaluated this performance deficiency using the traditional enforcement process because the failure to submit a required report affected the NRCs ability to perform its regulatory function. Consistent with the guidance in Section 2.2.2 and Section 6.9.d of the NRC Enforcement Policy, the inspectors concluded the finding was a Severity Level IV violation because the licensee failed to make a TS required report that resulted in no or relatively inappreciable potential safety consequences. In accordance with section 07.03.c of NRC Inspection Manual Chapter 0612 cross-cutting aspects are not assigned to traditional enforcement violations.
05000327/FIN-2012005-10	2012Q4	Sequoyah	Licensee-Identified Violation	In place of the controls required 20.1601(a) and b of 10 CFR Part 20, TS 6.12.2 requires that entryways into HRAs with dose rates exceeding 1 rem/hour at 30 cm be provided with a locked or continually guarded door or gate that prevents unauthorized entry. Contrary to this, on December 16, 2011, during the dewatering of a spent resin liner, the entryway into the Auxiliary Building Railroad Bay was controlled using remote monitoring and surveillance. During the resin transfer an individual was assigned as the access controller and a camera was placed in the area to monitor the LHRA. The access controller monitored the LHRA using the camera in Laundry/Trash Sorting area adjacent to the Railroad Bay behind a closed door. The dose rates on the top of the liner were 1500 mrem/hr at 30 cm. Although no unauthorized entry occurred during this time period, workers could have potentially entered the area from the Auxiliary Building Door. Although this event involved the failure to maintain proper control of a LHRA, this finding is of very low safety significance because there was neither evidence of unauthorized worker entry into the affected areas nor any unexpected radiation exposures to licensee personnel.
05000327/FIN-2012005-09	2012Q4	Sequoyah	Licensee-Identified Violation	Facility operating license DPR-79 condition 2.C.(13) states that TVA shall implement and maintain in effect all provisions of the approved fire protection program referenced in Sequoyah Nuclear Plants Final Safety Analysis Report and as approved in NRC Safety Evaluation Reports contained in NUREG-0011, Supplements 1, 2, and 5, NUREG-1232, Volume 2, NRC letters dated May 29, and October 6, 1986, and the Safety Evaluation issued on August 12, 1997, for License Amendment No. 218. Contrary to the above, on June 28, 2011, the licensee did not implement and maintain in effect all provisions of the approved fire protection program. Specifically, Sequoyahs Fire Protection Report Part II, Limiting Condition for Operation (LCO) 3.3.3.8.a.1 & 3.7.11.2.a.1 require a fire watch to be established when the required number of operable fire detection instruments and the required number of spray and/or sprinkler systems are inoperable. On January 3, 2012, the licensee discovered that standing Fire Protection Impairment Permit (FPIP) FOR110249 and the associated Fire Protection Report Part II action statement had been incorrectly entered. The licensee entered this issue into the corrective action program as PER 485817. The finding was screened using Inspection Manual Chapter 0609, Appendix F Fire Protection Significance Determination Process, and was determined to be of very low safety significance (Green).
05000327/FIN-2012005-08	2012Q4	Sequoyah	Licensee-Identified Violation	10 CFR 50, Appendix B, Criterion II, Quality Assurance Program, states, in part, that the quality assurance program shall provide control over activities affecting the quality of the identified structures, systems, and components, to an extent consistent with their importance to safety and that activities affecting quality shall be accomplished under suitably controlled conditions to include the use of appropriate equipment. Contrary to these requirements, the licensees quality assurance controls failed to ensure that critical fasteners utilized in reassembly of the sites motor-operated valves, specifically those utilized in safety-related service, were of the appropriate grade, class, or type, to meet design output requirements. The inspectors determined that the violation was not greater than of very low safety significance as it was determined that fasteners utilized would permit the valves to perform their function, although they were not acceptable per design. The issue is documented in the licensees CAP as TVA PERs 506338, 518423, 622076, 623383, 624373, 626982, and 644661.
05000327/FIN-2012005-07	2012Q4	Sequoyah	Licensee-Identified Violation	10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. The Quality Execution Procedure governing the licensees contractor for the steam generator replacement project, 11.01 paragraph 2.5.1a requires that work be performed in strict accordance with the Work Instructions provided in the applicable Work Package. Contrary to these requirements, in work packages 3575A/D for the 2-1 and 2-4 steam generator enclosure plugs, multiple steps for the welding of tapered shims were not performed as indicated in the work packages. The licensee found the omission in document review and closure, and performed rework to establish the requisite number of shims for the seismic support requirements of the subject enclosure plugs. The inspectors determined that the violation was not greater than of very low safety significance as it was identified and corrected with the reactor defueled in Mode 6. The issue is documented in the licensees CAP as the contractors Nonconformance Report (NCR) 1163, and TVA PER 655762
05000327/FIN-2012005-05	2012Q4	Sequoyah	Failure to Adequately Evaluate and Qualify Molded Case Circuit Breakers	The inspectors identified a violation with several examples of 10 CFR 50, Appendix B, Criterion III, Design Control, for failure to implement design control measures that review for suitability of application of materials, parts, and equipment that are essential to the safety-related functions of the structures, systems, and components and that provide for verifying or checking the adequacy of design such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program, including qualification testing of a prototype unit under the most adverse design conditions. The licensee entered this issue into the CAP as PER 668367. Failure of the licensee to ensure measures used to review the suitability of application of materials, parts, and equipment essential to the safety-related functions of molded case circuit breakers, and measures to provide for the verification of checking the adequacy of design were in place was a performance deficiency. This performance deficiency was more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, adequate measures were not implemented to ensure the station 120-VAC vital instrumentation boards had properly maintained their seismic qualification for their application. The inspectors assessed this finding for significance in accordance with NRC Manual Chapter 0609, Appendix A, Exhibit 2, Significance Determination Process (SDP) for Findings At- Power Mitigating Systems Screening Questions, and determined that it was of very low safety significance (Green) as the devices in question had been intrinsically qualified for this application as part of a complete panel test by the original vendor and the licensee determined that the SSC maintained its operability or functionality despite the identified non-conformances. The inspectors evaluated this finding and violation of NRC requirements in accordance with the NRC Enforcement Policy, Section 2.3.2, and found two conditions to not be met requiring a Notice of Violation be issued. First, inspectors found the licensee failed to restore compliance within a reasonable time after the original violation (05000327.328/2011002-01) was identified. The NRC Enforcement Manual, Section 3.1.2.A.1.b).1), further defines restoring compliance to include those actions taken to stop an ongoing violation from continuing. Second, the inspectors determined that the identified non-conformances represented a repetitive violation as a result of inadequate corrective action and that identification was by the NRC inspector. The lack of rigor in addressing the root of the prior violation which resulted in the inadequate corrective action further led the inspectors to identify a crosscutting aspect in the CAP component of the Problem Identification and Resolution area
05000327/FIN-2012005-04	2012Q4	Sequoyah	Failure to Perform ISI General Visual Examinations of Containment Moisture Barrier Associated with Containment Liner Leak Chase Test Connection Threaded Pipe Plugs	The inspectors identified a Green NCV of 10 CFR Part 50.55a, Codes and Standards, involving the licensees failure to properly apply Subsection IWE of ASME Section XI for conducting general visual examinations of the metal-to-metal pipe plugs installed in the containment liner channel weld leak chase test connections that provide a moisture barrier to the containment liner seam welds. Following the inspectors identification of this issue, the licensee conducted the visual examinations on all eight of the leak chase test connection upper cavities. These visual examinations revealed significant corrosion of the upper cavities, including one through-wall hole in the tubing leading down to the leak chase channels. Upon further inspection of the channels using a boroscope, the licensee noted water in the channels and corresponding corrosion. No through-wall condition was noted in any leak chase channel, and corrosion was limited to a very small percentage of the liner plate thickness. The licensee adequately evaluated the deficiencies prior to entering Mode 4 (Hot Shutdown) to ensure the integrity of containment was maintained. The issue was entered into the licensees CAP as problem evaluation report (PER) 636215. The failure to conduct a general visual examination of 100 percent of the moisture barriers intended to prevent intrusion of moisture against inaccessible areas of the containment liner at metal-to-metal interfaces which are not seal welded, was a performance deficiency that was within the licensees ability to foresee and correct. This finding was of more than minor significance because the failure to conduct required visual examinations and identify the degraded moisture barriers which allowed the intrusion of water into the liner leak chase channel, if left uncorrected, would have resulted in more significant corrosion degradation of the containment liner or associated liner welds. The finding was associated with the design control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, visual examinations of the containment metal liner provide assurance that the liner remains capable of performing its intended safety function. The inspectors used IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 Initial Screening and Characterization of Findings, and determined that the finding was of low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of the reactor containment. The inspectors identified a cross-cutting aspect in the Operating Experience component of the CAP cross-cutting area (P.2(b)). Specifically, the licensee failed to apply available Operating Experience from four other relevant industry issues to assure plant performance.
05000327/FIN-2012005-03	2012Q4	Sequoyah	Failure to Establish Adequate Procedures for Fire Protection Impairment Requirements	The inspectors identified a Green non-cited violation of Units 1 & 2 Technical Specification 6.8.1.f for the licensees failure to establish adequate procedures required for fire protection program implementation. Specifically, NPG-SPP-18.4.6, Control of Fire Protection, Revision 1 Impairments was determined to be inadequate because it did not provide any guidance on what a fire watch was supposed to do when they came to a protected door. The licensee entered this issue into the CAP program as PER 652672. Failure of the licensee to establish adequate procedures required for fire protection program implementation was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the protection against external events (fire) attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to establish adequate procedures required for fire protection program implementation caused compensatory measures (fire watches) to not be adequately completed and could have potentially compromised the ability to safely shutdown the plant in the event of a fire in any of the fire zones where the fire watches were required. The significance of this finding was evaluated in accordance with the IMC 0609 Attachment 4, Phase 1- Initial Screening and Characterization of Findings, which required further evaluation in accordance with Appendix F, Attachment 01, Part 1, Fire Protection SDP Phase 1 Worksheet. The finding was assigned to the fire prevention and administrative controls category and represented a low degradation level. The inspectors concluded that the finding was of very low safety significance (Green) based on a qualitative screening and the low degradation rating. The finding was determined to have a cross-cutting aspect in the Work Practices component of the Human Performance cross-cutting area (H.2(c)) for failure to provide adequate procedures for individuals conducting fire watches.
05000327/FIN-2012005-02	2012Q4	Sequoyah	Failure to Implement Fire Protection Impairment Requirements	The inspectors identified a Green non-cited violation of Units 1 & 2 Technical Specification 6.8.1.f for the licensees failure to implement procedures required for fire protection program implementation. The inspectors found multiple examples of where fire watches were not conducted in accordance with procedure NPG-SPP- 18.4.6, Control of Fire Protection Impairments, Revision 1, when required. The licensee entered this issue into the CAP program as PERs 635934 and 635934. Failure of the licensee to implement the requirements of procedure NPG-SPP-18.4.6, Control of Fire Protection Impairments, Revision 1, was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the protection against external events (fire) attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to perform compensatory measures (fire watches), could have potentially compromised the ability to safely shutdown the plant in the event of a fire in any of the fire zones where the fire watches were required. The significance of this finding was evaluated in accordance with the IMC 0609 Attachment 4, Phase 1- Initial Screening and Characterization of Findings, which required further evaluation in accordance with Appendix F, Attachment 01, Part 1, Fire Protection SDP Phase 1 Worksheet. The finding was assigned to the fire prevention and administrative controls category and represented a low degradation level. The inspectors concluded that the finding was of very low safety significance (Green) based on a qualitative screening and the low degradation rating. The finding was determined to have a cross-cutting aspect in the Work Practices component of the Human Performance cross-cutting area (H.4(c)) since the licensee failed to ensure that there was adequate supervisory and management oversight of fire watches.
05000327/FIN-2012005-01	2012Q4	Sequoyah	Failure to Implement Freeze Protection Program Requirements	A NRC-identified Green non-cited violation (NCV) of Unit 1 and 2 Technical Specification 6.8.1.a for the licensees failure to follow station procedures to adequately implement freeze protection requirements. Specifically, inspectors found a number of requirements improperly executed with no specific follow-up of those requirements contained within periodic instructions used to verify program implementation. The licensee placed the issue into the CAP and corrected the identified deficiencies. The inspectors determined that the failure to adequately implement all requirements of the licensees freeze protection program procedures was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was associated with the Mitigating System Cornerstone attribute of Protection against External Factors and adversely affected the cornerstone objective in that specific measures required for freeze protection were not properly implemented and station procedures did not maintain those expected conditions. The inspectors determined the finding was of very low safety significance (Green) as the site had not experienced significant freeze conditions yet this season. The cause of this finding was related to the cross-cutting aspect of ensuring personnel training is adequate to assure nuclear safety.
05000327/FIN-2012004-01	2012Q3	Sequoyah	Licensee-Identified Violation	10 CFR 50 Appendix B, Criterion V, required, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Contrary to this, on August 25, 2011, and again on September 6, 2012, the licensee failed to accomplish NPG-SPP-09.17, Temporary Equipment Control, an activity affecting quality, in accordance with the documented instructions. Specifically, Appendix A, Step C states, Specific Case Mechanical Engineering Evaluation is required if Temporary Equipment is placed inside primary containment during unit Operating Modes 1 through 4 at SQN. However, this step was not performed and material was brought into primary containment without a proper evaluation. This problem was entered into the licensees corrective action program as PERs 599247 and 604614. The finding was screened using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and determined the finding to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available.
05000390/FIN-2012008-01	2012Q2	Watts Bar	Failure to Establish Test Procedures to Assure Satisfactory Acas Performance During Design Basis Accidents	The team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for failure to perform capacity (volumetric flow) testing on the safety-related auxiliary control air subsystem (ACAS). The licensee had documented that, for worst case environmental conditions, the air compressor capacity had little margin when compared to required air demand, even for single unit operation. This issue was entered into the licensees corrective action program as problem evaluation report 501941 for further evaluation of corrective actions. The team determined that the failure to perform capacity testing to ensure the ACAS would meet the required air demand in response to a design basis event was a performance deficiency. This performance deficiency was more than minor because it affected the mitigating systems cornerstone attribute of equipment performance to ensure the availability, reliability, and capability of safety systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to develop a test procedure that would reliably ensure that the ACAS would meet required air demand for its safety-related loads during design basis accidents. The team performed a phase one significance determination process screening and determined the finding to have very low safety significance (green) utilizing the mitigating systems cornerstone column of IMC 0609, Attachment 4, Phase 1-Initial Screening and Characterization of Findings. The inspectors determined that the finding had a cross- cutting aspect in the use of conservative assumptions in the decision-making component of the human performance area. Specifically, the licensee did not use conservative assumptions in making the decision to discontinue capacity testing of the ACAS system in 2002, and stated that if that decision had been made more recently (using available internal guidance and practices regarding the testing of safety-related systems), the resulting decision would have been the same
05000390/FIN-2012008-02	2012Q2	Watts Bar	Failure to Adequately Test the AFW Discharge Check Valves	The team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the licensees failure to establish a test program that demonstrated the adequacy of the auxiliary feedwater (AFW) discharge check valves. Specifically, the licensee failed to develop a test program that would provide assurance that back leakage through the AFW discharge check valves would not prevent the system from providing design flow-rates to the steam generators. This issue was entered into the licensees corrective action program as problem evaluation report 499950. The licensee performed a functional evaluation and determined that the AFW system was operable based on the pumps not currently being degraded to the design limits, and the existence of additional conservatisms in the licensees design basis hydraulic analysis. The team determined that the licensees failure to establish a test program to ensure that back leakage through the AFW discharge check valves would not challenge the ability of the AFW system to provide design basis flow to the steam generators was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, it could have the potential to lead to a more significant safety concern. Specifically, AFW check valve back leakage could challenge the systems ability to support removal of decay heat from the reactor, which would not be identified by the licensees test program. The team performed a phase one significance determination process screening and determined the finding to have very low safety significance (green), utilizing the mitigating systems cornerstone column of IMC 0609, Attachment 4, Phase 1- Initial Screening and Characterization of Findings. Because the licensee performed a self-assessment in December 2011 that included missed opportunities to identify that check valve leakage could negatively impact the AFW system, this finding was assigned a cross-cutting aspect in the self- and independent assessments component of the problem identification and resolution area
05000390/FIN-2012008-03	2012Q2	Watts Bar	Inadequate Acceptance Criteria in Maintenance and Surveillance Procedures (5 Examples)	The team identified five examples of a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to correctly translate vendor specifications and design calculations into maintenance and surveillance procedures. The five examples were entered into the licensees corrective action program. The inspectors determined that the failure to correctly translate vendor specifications and design calculations into maintenance and surveillance procedures was a performance deficiency. The performance deficiency was more than minor because it affected the mitigating systems cornerstone attribute of design control, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In addition, the finding is similar to Inspection Manual Chapter 0612, Appendix E (example 4.a), because the failure to ensure correct translation of acceptance criteria into procedures was not isolated. The team performed a phase one significance determination process screening and determined the finding to have very low safety significance (green) utilizing the mitigating systems cornerstone column of IMC 0609, Attachment 4, Phase 1-Initial Screening and Characterization of Findings. This finding had a cross-cutting aspect in the resources component of the human performance area, because the licensee had not ensured that complete, accurate, and up-to-date procedures were consistent with vendor and design specifications; and therefore, the procedures were not available and adequate to assure nuclear safety
05000390/FIN-2012008-04	2012Q2	Watts Bar	Effect of System Harmonics on Degraded Voltage Relay Function	The team identified an issue of concern and an unresolved item related to the effect of electrical system harmonics on safety-related degraded voltage relays. Specifically, in 1993, the licensee identified that harmonic distortions adversely affected the 6.9 kilovolt (kV) bus overvoltage relays by causing them to alarm unnecessarily. The licensee entered this issue into their corrective action program and modified the overvoltage relays to minimize the effects. However, the licensee did not identify (or otherwise evaluate) the adverse effect that harmonics could have on the ability of the degraded voltage relays to perform their safety function, as required by limiting condition for operation 3.3.5 of the plants technical specifications. The Watts Bar degraded voltage protection scheme features three ABB type 27N relays for each 6.9 kV safety bus, arranged in a two out of three tripping scheme. The ABB instruction bulletin 7.4.1.7-7 contained in vendor manual WBN-VTD-AS04-0080 states that (1) the relay employs a peak voltage detector, and (2) harmonic distortion on the AC waveform can have a noticeable effect on the relay operating point and the measuring instruments used to calibrate the relay. The bulletin also notes that the relay is available with an internal harmonic filter for applications where waveform distortion is a factor. The team noted that calculation WBPE2119202001, 6.9kV Shutdown & Logic Boards Under-voltage Relay Requirements/Demonstrated Accuracy Calculation, identified the relay as a model not equipped with a harmonic filter, but did not address the basis for excluding harmonic distortion as a factor which affected relay accuracy. In response to the teams inquiries, the licensee provided PER 930397 that addressed spurious actuations of the ABB type 59H overvoltage relays which are similar in design to the ABB type 27N degraded voltage relays. Troubleshooting tests performed to identify the cause of the 59H spurious actuations revealed that high levels of 6.9 kV system harmonics from sources both external and internal to the station accompanied the spurious operations. The causal factor section of PER 930397 stated that the relays sometimes trip on harmonic distortion although the root mean square voltages are at acceptable levels. Corrective actions consisted of replacing the type 59H overvoltage relays with a model equipped with harmonic filters. The team further noted that the extent of condition section of PER 930397 did not identify or address whether the degraded voltage relays operating point could also be affected by the same harmonics implicated in the mal-operation of the overvoltage relays. The team was concerned that harmonics on the 6.9 kV system could cause the degraded voltage relays to fail to actuate at the set-point specified by technical specifications. Persistent harmonics can be produced by factors external to the nuclear site or by internal phenomena. A typical internal source of harmonics at nuclear power plants is motor defects. The team was also concerned that transient harmonics could cause the relays to spuriously reset during an actual degraded voltage event, thereby delaying the protective function beyond the 10 seconds stipulated in technical specification limiting condition for operation 3.3.5. Specifically, the degraded voltage relays design features an instantaneous reset characteristic that could allow reset of the degraded voltage relay in less than two cycles in the presence of harmonics, thereby reinitiating the external 10 seconds timer. The reset function of the existing degraded voltage relays is identical to the tripping function of the overvoltage relays that actuated due to transient harmonics in 1993. In 1993, transient harmonics were measured at levels of greater than 10% total harmonic distortion during the troubleshooting for PER 930397 versus the 0.3% distortion deemed acceptable by the relay vendor. The transient harmonics documented in PER 930397 were attributed to events that included the trip of the nearby Sequoyah generating station, and to breaker operations at the Watts Bar station. The team noted that similar conditions could exist during an accident scenario when proper performance of the degraded voltage scheme time delay would be critical with respect to satisfying the response time assumptions in the accident analysis. In response to the teams concerns, the licensee provided information regarding condition monitoring of large motors that consisted of periodic measurement and analysis of motor bearing vibration from which various defects that may produce harmonics could be identified. The team noted, however, that there was no written guidance or acceptance criteria for these tests that would prompt engineering to investigate whether suspected motor defects could produce harmonics that would adversely affect the accuracy of degraded voltage relays. Specifically, there was no recognition in design or maintenance documents regarding the susceptibility of the degraded voltage relays to harmonic distortion, or the need to investigate suspected motor defects with respect to this susceptibility. The team further noted that during normal bus voltage conditions when voltage is above the degraded voltage relay reset set-point, harmonics would shift system peak voltage away from the degraded voltage relay operating set-point rather than closer to it, and so the presence of harmful harmonics would not self-reveal by spurious actuations. The overvoltage relays are now equipped with harmonic filters so they will also not reveal the presence of either transient or persistent harmonics. Based on the teams observations, the licensee has entered these concerns into their corrective action program as PER 515413 and PER 546072. The team determined that additional review of information recently received from the licensee regarding Watts Bars design and licensing bases was necessary to determine if the licensees performance constituted a violation of NRC regulatory requirements. Additionally, the team determined that additional consultation with the Office of Nuclear Reactor Regulation was warranted before reaching a final disposition of the unresolved item. This unresolved item is open pending (1) the review of additional information from the licensee regarding the design and licensing basis of the degraded voltage relays and (2) consultation with the Office of Nuclear Reactor Regulation: URI 05000390/2012008-04, Effect of System Harmonics on Degraded Voltage Relay Function.
05000390/FIN-2010005-02	2010Q4	Watts Bar	Failure to Adequately Qualify Molded-Case Circuit Breakers to Safety-Related Application Through Commercial Grade Dedication	The inspectors identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for the failure to assure that appropriate quality standards were specified and included in design documents and that deviations from such standards were controlled. Specifically, the licensee failed to demonstrate the necessary conditions for commercial grade dedication and seismic qualification of molded case circuit breakers to safety-related application within the station 120VAC vital instrumentation boards. Corrective actions for this issue are still being evaluated and has been entered into the licensees corrective action program as PER 171695. Failure to specify appropriate qualification standards in performing commercial grade dedication of a component-level commodity is a performance deficiency. This performance deficiency is more than minor and a finding because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, adequate measures were not implemented to ensure the station 120VAC vital instrumentation boards were properly seismically qualified for their application. The inspector assessed the finding using the SDP and determined that the finding was of very low safety significance (Green) because the breaker panels had originally been qualified by testing a complete prototype panel, while the licensees processes replaced a componentlevel item within that panel utilizing the original make and model component through commercial grade dedication. The inspectors concluded that overall operability was not brought into question. This finding was reviewed for cross-cutting aspects and none were identified, as it was determined not to reflect current licensee performance.
05000390/FIN-2010005-03	2010Q4	Watts Bar	Failure to Use Worst Case 6900 VAC Bus Voltage in Design Calculations	The inspectors identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for the failure to assure that applicable regulatory requirements and the design basis for structures, systems, and components are correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee failed to assure that applicable regulatory requirements for undervoltage (degraded) voltage protection, including those prescribed in TS 3.3.5-1, item 2, were correctly translated into design calculation, WBN-EEB-MS-TI-06-0029, Degraded Voltage Analysis, Revision. 31, which evaluated motor starting voltages at the beginning of a design basis loss of coolant accident (LOCA) concurrent with a degraded grid condition. Corrective actions for this issue are still being evaluated and has been entered into the licensees corrective action program as PER 296306. The failure to use the degraded voltage relay setpoint values as specified in TS and configured in the 6900 VAC bus based on the electrical design calculation was a performance deficiency. This finding is more than minor because it affects the Design Control attribute of the Mitigating Systems Cornerstone. It impacts the cornerstone objective of ensuring the availability, reliability, and operability of the 6900 VAC safety buses to perform the intended safety function during a design basis event. The potential availability, reliability, and operability of the 6900 VAC safety buses during a potential degraded voltage condition was impacted as the licensee design calculation used a non-conservative degraded voltage input, with respect to the values specified in TS, into their safety-related motor starting and running calculations. The inspectors assessed the finding using the SDP and determined that the finding was of very low safety significance (Green) because the finding represented a design deficiency confirmed not to result in the loss of functionality of safety-related loads due to the availability of related transformer load tap changers (LTCs) that were installed to improve a degraded voltage condition. The inspectors reviewed the performance deficiency for cross-cutting aspects and determined that none were applicable since this performance deficiency was not indicative of current licensee performance as the design calculation discussed above was not recently performed.
05000321/FIN-2010003-04	2010Q2	Hatch	1A EDG fuel oil return line failure	An unresolved item (URI) was opened related to CR 2010104391, fuel oil return line fitting failure on the 1A EDG. As of the end of this inspection period the licensee had not completed their investigation into this issue. The determination of a performance deficiency cannot be made until the licensee completes and documents their inspection efforts in this area On April 1, 2010 a fitting leak on the 1A EDG fuel oil return line was identified by the licensee during a monthly surveillance test run. CR 2010104391 documents that an attempt was made to tighten the fitting but the leak continued and that the leak needed to be repaired after the monthly surveillance test run was complete. The leak on this fitting was added to existing WO 1092436001 and scheduled for the 1A EDG system outage in May 2011. On June 3, 2010 during the monthly surveillance test run, the tubing associated with this fitting failed and diesel fuel oil was identified spraying onto the 1A EDG exhaust. The surveillance test run was terminated and the 1A EDG was secured by local operators in order to prevent a fire from starting. The failure of the 1A EDG fuel oil tubing was documented in CR 2010107248. URI 05000321/2010003- 04, 1A EDG fuel oil return line failure, will be identified to track this issue pending review of the investigation conducted under CR 2010107248 to evaluate whether this issue constitutes a performance deficiency.
05000321/FIN-2010003-02	2010Q2	Hatch	Failure to follow corrective action program procedure and prevent recurrence of severity level 2 root cause	A self-revealing NCV of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures and Drawings, was identified for the licensees failure to follow their corrective action program procedure, NMP-GM-002, Ver. 4.0, that required severity level 1 and 2 condition reports (CR) to have corrective actions that prevent recurrence. From May 2006 to April 2010 licensee procedure NMP-GM-002, Corrective Action Program, Ver. 4.0, was not followed because corrective actions to prevent recurrence were not implemented prior to failure of Analog Transmitter Trip System (ATTS) card 1B21-N641C. The licensees immediate corrective actions were to replace the failed card, 1B21-N641C, the adjacent card 1B21-N690C and the high drywell pressure trip cards 1E11-N694A and C. The licensee initiated CR 2010105161 to address this issue. The performance deficiency is more than minor because it is associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the Initiating Events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure of ATTS card 1B21-N641C resulted in a spurious Loss of Coolant Accident (LOCA) signal that started Emergency Core Cooling System (ECCS) equipment and resulted in a power reduction to approximately 85%. Due to this finding affecting the safety of an operating reactor, the significance of this finding was screened using NRC IMC 0609, Attachment 4, Table 4a. Because the finding contributed to the likelihood of a reactor scram, but did not affect mitigation equipment availability, the finding screened as Green. The inspectors concluded that the performance deficiency does not have an associated cross-cutting aspect because the performance deficiency occurred in 2006 and is not indicative of the licensees current performance in the area of root cause investigations.
05000321/FIN-2010003-03	2010Q2	Hatch	Failure to follow procedure while in shutdown cooling to record corrected reactor water level	The NRC identified a NCV of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to prescribe in procedure 34GO-OPS-015-2, Maintaining Cold Shutdown or Refueling Condition, appropriate documented instructions for recording and verifying reactor water level when reactor vessel level is greater than 60 inches and instrument 2B21-R605 is unavailable. To address this issue the licensee performed the immediate corrective action of initiating CR 2010104615 and has generated an action item to upgrade procedure 34GO-OPS-015-2. This performance deficiency is more than minor because it is associated with the Human Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability of systems (ability of operators to monitor, trend, and maintain reactor water level) to prevent undesirable consequences. Because this finding is associated with the safety of a reactor while the unit was in cold shutdown and on residual heat removal shutdown cooling, NRC IMC 0609, Attachment 4, directs using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, to determine the significance of this finding. In Appendix G, Attachment 1, Checklist 6 was used because during the time period of this finding the unit was in cold shutdown, with a time to boil < 2 hours, and reactor coolant system level < 23 feet above the top of the reactor vessel flange. Each item in Appendix G, Attachment 1, Checklist 6 was determined to have been met, therefore per Figure 1 of Appendix G this finding screened as GREEN significance because a Qualitative Assessment was not required by Checklist 6. This finding has a cross-cutting aspect in the Work Control component of the Human Performance area, because the licensee did not plan and coordinate work activities consistent with nuclear safety including planned contingencies, compensatory actions, or abort criteria. Specifically, the licensee did not plan and coordinate the activity of transitioning the reference leg for reactor water level instrument 2B21-R605 with contingencies, compensatory actions, or abort criteria addressed to ensure measurable reactor water level was available to control room operators.
05000321/FIN-2010003-01	2010Q2	Hatch	Failure to maintain safety related cables in a nonsubmerged environment	The NRC identified a NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensees failure implement measures to assure that safety-related cables remained in an environment for which they were designed. Safety-related cables purchased and installed in underground electrical pull boxes at Hatch Nuclear Plant have been subjected to submergence, a condition for which they are not designed. To address this issue the licensee has performed the immediate corrective action of increasing the frequency of measuring water level and pump down of the pull boxes. The licensee initiated CR 2010104298 to address this issue. This performance deficiency is more than minor because it is associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, it is reasonable to conclude the cables may be in a degraded condition where the continued reliability of the cable cannot be ensured because: 1) the licensee does not have a cable testing/monitoring program to detect degradation of inaccessible or underground power cables; 2) the cables have been subject to a submerged physical environment which is outside the cables design parameters; and 3) there have been documented failures of cables throughout the nuclear industry due to degradation caused by submergence in water. Because the finding affects the safety of an operating reactor, the significance of this finding was screened using the Phase 1 of the SDP in accordance with NRC IMC 0609, Attachment 4, Table 4a. The finding screened as Green, because the finding is a design or qualification deficiency confirmed not to result in loss of operability or functionality. This finding has a cross-cutting aspect in the Work Control component of the Human Performance area, because the licensee did not appropriately coordinate activities by incorporating actions where maintenance scheduling is more preventive than reactive. Specifically, the licensee did not schedule performance of procedure 52PM-Y46-001-0, Inground Pull Box and Cable Duct Inspection for Water, at a frequency that prevented safety related cable submersion
05000321/FIN-2010003-06	2010Q2	Hatch	Licensee-Identified Violation	TS 3.4.3 requires 10 of 11 SRVs to be operable during Modes 1, 2 and 3. Contrary to the above, on March 11, 2010 on Unit 1 it was identified during bench testing that five safety relief valves failed to lift at the required TS setpoint. The cause was found to be corrosion induced bonding between the pilot disc and seating surface. This condition was documented in CR 2010103338. This finding is of very low safety significance because a previous evaluation performed by the licensee bounds this condition and RCS pressure would be maintained below the TS safety limit.
05000321/FIN-2010003-05	2010Q2	Hatch	Licensee-Identified Violation	TS 5.4.1.a requires written procedures be established, implemented and, maintained covering the activities specified in Regulatory Guide 1.33, Appendix A. Items 2g and 4a of Appendix A requires procedures for general power operation and operation of the reactors recirculation system to be established and implemented. Contrary to the above, Unit 2 operated at a core flow higher than that allowed on the power/flow map described in licensee procedure 34GO-OPS-005-2, Power Changes. This issue was documented in the licensees corrective action program as CR 2009108237. Because the finding is associated with the fuel barrier and sufficient fuel thermal limit margin was maintained during the time core flow was outside the bounds of the power/flow map, this finding is of very low safety significance.
05000390/FIN-2010006-01	2010Q2	Watts Bar	Inadequate Assessment of Seismic Qualification of ERCW Strainers	The team identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensees failure to update ERCW strainer mounting (seismic/structural) calculations to reflect the as-built conditions, a failure which was allowed to exist since commercial operations began. This calculation was then used in making acceptance conclusions for a modification installed in recent months. The licensee entered this condition into their corrective action program as Problem Evaluation Reports (PERs) 221018, 220754, and 223677 and took immediate actions to determine the seismic acceptability of the current installation, utilizing calculational conclusions of a similar installation at the licensees Sequoyah Nuclear Plant. The finding was determined to be more than minor because it was associated with the design control attribute within the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, in that there was reasonable doubt as to the operability of the ERCW strainers as a result of the performance deficiency. The team evaluated the finding to be of very low safety significance (Green) utilizing IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings worksheet, as it was a calculational error subsequently determined to not result in an operability issue. No cross-cutting aspect was identified since the issue was not reflective of current licensee performance
05000390/FIN-2010006-02	2010Q2	Watts Bar	Worst Case 6900 VAC Bus Voltage in Design Calculations	The team indentified an Unresolved Item (URI) regarding calculations that supported the degraded voltage protection scheme. The calculations that analyzed the Class 1E 6900 VAC and 480 VAC motor loads take credit for administratively limiting the minimum 161kV offsite power supply bus voltage and credit performance of the nonsafety- related automatic load tap changers on the common station service transformers (CSSTs) to limit the minimum voltage on the Class 1E 6900 VAC and 480 VAC buses. The calculations did not evaluate the Class 1E 6900 VAC and 480 VAC motor loads at the worst possible case low voltages which could drop as low as the bottom end of the acceptable tolerance band of the degraded voltage relays. Offsite power is normally provided to the Class 1E 6900 VAC buses from the 161kV offsite power system through the CSSTs. The CSSTs have non-safety automatic load tap changers which are designed to maintain approximately 6900 VAC on the Class 1E buses through a dynamic range of 161kV offsite power supply voltages. The Class 1E 480 VAC buses are then powered from fixed-tap 6900/480VAC transformers powered from the respective Class 1E 6900 VAC buses. NUREG-0800, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants, Appendix 8-A, Branch Technical Position PSB-1: Adequacy of Station Electric Distribution System Voltages, Rev. 2 (07/1981) is part of the licensing basis for the Watts Bar Nuclear Plant. This document states, in part, that the selection of under-voltage and time-delay setpoints shall be determined from an analysis of the voltage requirements of the Class 1E loads at all onsite distribution levels. Watts Bar calculation WBNEEBMSTI060029, Degraded Voltage Analysis, Rev. 31, evaluated transient motor starting voltages at the beginning of a design basis loss of coolant accident (LOCA). This calculation was based on the voltages where the minimum 161kV offsite power supply bus voltage was limited by taking credit for administrative controls rather than assuming a worst-case 161kV offsite power supply voltage drop which would still allow voltage recovery to the degraded voltage relay reset setpoint (minus setpoint tolerance) before the expiration of the degraded voltage relay nominal 10 second time delay, and thereby leave the Class 1E 6900 VAC buses connected to the offsite power supply. In addition, calculations for motor starting during steady-state conditions credited voltage improvement based on performance of the non-safety related CSST automatic load tap changers instead of being based on worst-case conditions. Summary. This issue is unresolved pending further inspection to determine (1) the actual worst-case voltage required to be analyzed on the Class 1E 6900 VAC and 480 VAC buses for safety-related loads in accordance with the facility licensing basis; and (2) the impact of not using the worst-case bus voltage afforded by the degraded voltage protection scheme in safety-related 6900 VAC and 480 VAC motor starting studies. Additionally, this issue is very similar to a URI reported in the Sequoyah Nuclear Plants inspection report 05000327,328/2010007-01. (URI 05000390/2010006-02, Worst Case 6900 VAC Bus Voltage in Design Calculations
05000321/FIN-2009005-01	2009Q4	Hatch	Submerged safety-related medium voltage cables	An unresolved item (URI) was opened related to underground pull box inspections which revealed a safety-related 4160 volt cable located in two pull boxes was submerged under water. The determination of a performance deficiency cannot be made until further information is provided by the licensee to support that the cables are designed, qualified, and acceptable for operation in a wetted and/or submerged environment. On December 10, 2009 during inspection of underground bunkers subject to flooding, the inspectors identified that safety-related 4160 volt cable, R22-S005-ES1- M08, located in pull boxes PB1-BF and PB1-BB was submerged. This issue was captured in the licensees corrective action program as CR 2009111808. The inspectors require documentation supporting the cables design, qualification, and testing history to evaluate whether this issue constitutes a performance deficiency. URI 05000321,366/2009005-01, Submerged safety-related medium voltage cable was identified to track this issue
05000338/FIN-2009007-02	2009Q4	North Anna	Failure to Ensure RSST A LTC Controller Settings were Correctly Implemented	The inspectors identified a finding having very low safety significance (Green) involving the failure of the licensee to ensure that the control settings for the non-safety related reserve station service transformer (RSST) A replacement load tap changer (LTC) controller installed through design change package (DCP) 05-108 were correctly implemented such that the LTC could respond as expected and credited across the range of design conditions. The licensee declared the RSST inoperable and implemented a change to the controller settings in compliance with design, and is tracking further actions under CR358215. The inspectors concluded that the finding was more than minor in that it is associated with the reactor safety mitigating systems cornerstone attribute of equipment performance and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure of the LTC to operate, as credited, due to incorrect LTC controller set points or inadequate control voltages, would have caused the 4kV safety related buses to prematurely disconnect from offsite power during a design basis event. The finding is of very low safety significance as it did not result in an actual loss of safety function. Further, this finding did not constitute a violation of NRC requirements as the RSST A is a non-safety related component. The team also evaluated the finding for cross-cutting aspects and determined it to involve a failure to ensure adequately trained resources were available to design, check, and review complex digital controllers and their settings, and so involved the human performance (H) resources component cross cutting aspect (H.2.(c)
05000338/FIN-2009007-03	2009Q4	North Anna	Failure to Ensure the Adequacy of Control Voltage to the 4160 and 480 VAC Equipment	The team identified a finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to ensure the adequacy of control voltage to the 4160 and 480 VAC equipment in support of mitigating system loads; specifically, a lack of voltage drop analysis for 125 VDC control power to breaker open/close coil, spring charging motors, and other miscellaneous DC loads. The licensee entered this issue into the corrective action program as CR361181.The inspectors concluded that the finding is more than minor in that it involves the mitigating systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined the failure to assure and verify that adequate control voltage was available to close and open the 4160 VAC and 480 VAC breakers could have affected the capability of safety-related equipment to respond to initiating events. The finding is of very low safety significance as it did not result in an actual loss of safety function. The team also evaluated the finding for cross-cutting aspects and none were identified as this was determined to not be indicative of current licensee performance.
05000338/FIN-2009007-01	2009Q4	North Anna	Failure to Perform Periodic TOL Testing on Unit 1	The team identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the licensees failure to assure that thermal overload protection devices (TOLs) on safety-related motor-operated valve (MOV) circuits of Unit 1 were periodically tested to ensure that trip set point drift does not affect the reliability or availability of mitigating systems when called upon to operate. The licensee entered this issue into the corrective action program as CR361181.The inspectors concluded that the finding was more than minor in that the finding involves the mitigating systems cornerstone attribute of procedure quality and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inspectors determined that the failure to assure that TOLs would not unnecessarily prevent safety related valves from performing their function. This could affect the availability and ability of MOVs to respond to initiating events. As no failures due to TOL performance were identified by the inspectors which would affect plant response, the inspectors determined this finding and violation of regulatory requirements to be of very low safety significance. The finding was reviewed for cross-cutting aspects and none were identified as this was determined to not be indicative of current licensee performance.
05000413/FIN-2009006-01	2009Q4	Catawba	Failure to monitor the turbine-driven auxiliary feedwater pump sump valves for units 1 and 2	The team identified a non-cited violation of 10 CFR 50.65(a)(1) for the licensees failure to monitor the turbine-driven auxiliary feedwater pump (CAPT) sump valves for Units 1 and 2. PIPs C-09-05020 and C-09-04390 initiated immediate corrective actions, including testing of the subject valves during the inspection, wherein valve 1WL848 failed to stroke. Additionally, the licensee increased the maintenance category of the affected components and made procedural modifications to provide positive valve position controls. The team determined that the licensees failure to monitor the performance and condition of Valve 1WL848 was a performance deficiency. This finding is more than minor because it is associated with equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to perform periodic testing or preventative maintenance resulted in a lack of reasonable assurance that the valves would perform their function of protecting CAPT. The team determined that the finding is of very low safety significance (Green) using the SDP because the finding did not represent an actual loss of safety function. This finding was reviewed for cross-cutting aspects and none were identified since the performance deficiency was not indicative of current licensee performance
05000321/FIN-2009006-06	2009Q3	Hatch	Failure to Monitor the Main Steam and Feedwater Line Pipe Whip Restraints	The team identified a non-cited violation of 10 CFR 50.65(a)(1) for the licensees failure to monitor the main steam line and feedwater line pipe whip restraints for Units 1 and 2. The licensee initiated CRs 2009105147 and200910622 and plans to complete inspections of the whip restraints during the upcoming Units 1 and 2 outages. The licensees failure to periodically inspect the condition of the safety-related pipe whip restraints was a performance deficiency. The finding is more than minor because it is associated with Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined that the finding is of very low safety significance (Green) using the SDP because the finding did not represent an actual loss of safety function. The finding directly involved the cross-cutting aspect of implementing a corrective action program with a low threshold for identifying issues under the Corrective Action Program component of the Problem Identification and Resolution area
05000321/FIN-2009006-07	2009Q3	Hatch	Postulated Early Transfer of Non-Safety Buses	The team identified an Unresolved Item (URI) regarding the licensees calculation that evaluated the adverse effects of a postulated early transfer of non-safety buses to a start-up transformer that energizes safety-related buses. Unit 2 utilizes three safety-related buses (2E, 2F, and 2G) to energize emergency core cooling system equipment. Safety-related buses 2F and 2G are normally connected to the same winding of start-up transformer 2D. Hatch utilizes a fast transfer scheme that allows the same winding of the start-up transformer 2D to energize non-safety bus 2D following a main generator trip. The fast transfer results in non-safety bus 2D and safety-related buses 2F and 2G being energized from the same winding of start-up transformer 2D.For a main generator trip thats caused by high drywell pressure or low reactor water level, the fast transfer of non-safety bus 2D occurs several seconds after the large ECCS motors have block started onto the safety-related buses 2F and 2G. If a single failure is postulated, the fast transfer would be concurrent with ECCS block motor starting. A postulated single failure could be caused by the faults to the following components: UAT relaying, normal supply breaker circuits, or main generator tripping scheme. The effect of the fast transfer occurring with a postulated single failure is that the electrical power for two trains of safety-related equipment would be adversely affected. The licensee analyzed the vulnerability described above in Calculation SENH 92-133,Bus Transfer Study, Rev. 1 and determined that if a failure as described above occurred, safety-related bus voltage would dip to approximately 48% of 4160V for 1.09seconds during motor starting. Calculation SENH 92-133 showed that large motors would start, but the team had additional questions regarding modeling techniques used for systems experiencing voltage dips greater than 30%. In addition, the team had questions regarding why the calculation did not evaluate the effect of the voltage dip on other safety related equipment connected to the system. This item is unresolved pending the NRCs review of Calculation SENH 92-133 to determine the adequacy of the methodology, and the NRCs review to determine if the postulated scenario is within the Hatch licensing bases. The issue is applicable to both Units 1 and 2. (URI 05000321/2009006-07 and 05000366/2009006-07, Postulated Early Transfer of Non-Safety Buses
05000321/FIN-2009006-08	2009Q3	Hatch	Degraded Voltage Protection	The team identified an Unresolved Item (URI) regarding the Hatch degraded voltage protection scheme. The existing automatic degraded voltage protection scheme employs automatic setpoints that are too low to assure operability of safety related electrical equipment in case of a sustained degraded grid condition, and instead relies on administrative controls to assure adequate voltage to safety-related equipment during an accident. In 1991, the NRC Engineering Design Safety Function Inspection determined that Hatchs calculations for the setpoints of the inverse time degraded undervoltage protection relays, then set at approximately 78.8% with a 20 second delay, were not adequate. Hatch updated the voltage calculations, and indicated in a letter dated November 22, 1993 that the setpoints would need to be raised to approximately91% of 4160V at the 4160V safety buses in order to ensure adequate voltage to safety related loads during a LOCA. Graphs attached to the letter showed that required LOCA voltages ranged from 88.46% to 90.8% for the three 4160V safety buses. During the inspection, Hatch was not able to locate calculations that supported the values (88.46%to 90.8%) given in the graph. Hatch concluded that raising the trip setpoint to 91% would result in little margin between the trip setpoint at which the buses would be separated from offsite power, and the minimum bus voltage that could occur if offsite declined to the lower end of its expected range (101.3% of 230kV). Because of the increase in risk of spurious separation of the offsite power supply that would have occurred if the trip setting of the undervoltage relay was raised, Hatch proposed a scheme where the trip setpoint of the relays providing the automatic separation feature would remain at its existing setting, and additional relays providing an alarm function would be installed, with a setpoint of approximately 92%. In addition, Hatch agreed to maintain a minimum switchyard voltage of 101.3% of 230kV, supported by a software based contingency alarm operated by the transmission system operator. This scheme was recognized as a deviation from the guidance on degraded voltage protection provided in NRC generic letter dated June 2, 1977 because it relied on an alarm followed by manual operator action, in lieu of automatic protection, but it was accepted by the NRC in an SER dated February 23, 1995. Consequently, Hatch is currently relying on measures implemented and maintained by their transmission system operator to assure adequate power to safety related equipment during an accident. This item is unresolved pending further NRC review of plant design and prior NRC inspections related to this issue. (URI 05000321/2009006-08 and05000366/2009006-08, Degraded Voltage Protection)
05000321/FIN-2009006-01	2009Q3	Hatch	Failure to Perform Cause Determinations and Corrective Actions for Deficiences in Containment Penetration Seals	The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to promptly correct deficiencies in containment penetration seals. The licensee initiated CR2009105747 to evaluate corrective actions for the seals. The team determined that the failure to take corrective actions for deficiencies in containment penetration seals was a performance deficiency. The finding is greater than minor because it is associated with the Structures, Systems and Components (SSC) and Barrier Performance attribute of maintaining functionality of containment and affected the cornerstone objective of providing reasonable assurance that containment protects the public from radionuclide releases caused by accidents or events. The finding is of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment. The finding directly involved the crosscutting aspect of thoroughness of evaluation within the Corrective Action Program component of the Problem Identification and Resolution area
05000321/FIN-2009006-02	2009Q3	Hatch	Failure to Correctly Establish Containment Isolation Valve Leakage Criteria for the Unit 2 Feedwater Check Valves	The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for failure to correctly establish containment isolation valve leakage criteria for Unit 2 feedwater check valves. The licensee initiated CR 2009104567 and revised the associated calculation during the inspection. The team determined that the failure to correctly establish leakage acceptance criteria for the feedwater check valves was a performance deficiency. The finding is greater than minor because it is associated with the SSC and Barrier performance attribute of maintaining functionality of containment and affected the cornerstone objective of providing reasonable assurance that containment protects the public from radionuclide releases caused by accidents or events. The finding is of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment. The finding directly involved the cross-cutting aspect of complete, accurate and up-to-date design documentation within the Resources component of the Human Performance area
05000321/FIN-2009006-03	2009Q3	Hatch	Non-Interruptible Essential Instrument Air Header Check Valves for Units 1 and 2	The team identified an Unresolved Item (URI) regarding non-interruptible essential instrument air header check valves for Units 1 and 2. The licensee had not performed periodic maintenance or testing that demonstrated the capability of the check valves to prevent back-flow during a loss of instrument air event. During a loss of instrument air event, the back-up nitrogen system automatically pressurizes the non-interruptible essential air system with nitrogen. Then on-interruptible essential air header is designed with check valves that function as a boundary between instrument air and non-interruptible essential air. The boundary check valves prevent the loss of back-up nitrogen through postulated breaks in the instrument air system. The team noted that emergency operating procedures utilize the back-up nitrogen system for operation of the hardened containment vent, which is a dominant contributor to the plants overall core damage frequency risk profile, during loss of instrument air events. The licensee scoped the function of the non-interruptible essential air system into the maintenance rule program as documented in the Performance Criteria dated June 19, 1998. Since initial plant start-up of Units 1 and 2, the licensee had not performed periodic maintenance or testing that demonstrated the capability of the check valves to prevent back-flow during a loss of instrument air event. The team determined that the lack of periodic maintenance or testing resulted in a lack of reasonable assurance that the valves could perform their design function if called upon. The licensee initiated CR2009105109 for this issue and provided interim guidance to operators for responding to a loss of instrument air event. This issue is unresolved pending further inspection and interface with the licensee to determine the extent of condition and impact from the lack of periodic maintenance or testing of the non-interruptible essential instrument air header check valves. (URI 05000321/2009006-03 and 05000366/2009006-03, Non-Interruptible Essential Instrument Air Header Check Valves for Units 1 and 2
05000321/FIN-2009006-04	2009Q3	Hatch	Reactor Building Equipment Drain Sump System for Units 1 and 2	The team identified an Unresolved Item (URI) regarding the licensees failure to scope and monitor the Reactor Building Equipment Drain Sump System for Units 1 and 2 in the maintenance rule program. The torus room and the reactor building diagonal rooms are equipped with instrumented floor drain sumps. The diagonal rooms house the High Pressure Core Injection (HPCI), Reactor Core Injection Cooling (RCIC), Control Rod Drive, Core Spray, and RHR pumps. The instrumented sumps are isolatable from each other by means of air operated valves (AOV). Automatic closure of the normally open AOVs isolates the reactor building diagonal rooms, which prevents the spread of water from room to room. The AOVs are automatically closed when high water levels are detected by sump level switches. FSAR, Section 9.3.3, states in part that a single failure of a level switch will not prevent sump isolation from occurring. The team determined that the licensee failed to scope and monitor the Reactor Building Equipment Drain Sump System in their maintenance rule program since 1996. The teams preliminary review of corrective action documents, surveillance records, and work orders revealed a lack of functional testing on Unit 1, repetitive failures of AOVs during weekly surveillance testing on both Units 1 and 2, and inadequate corrective actions for repetitive AOV failures. Additionally, the teams questioning revealed that the design of the level switches did not meet the single failure criteria as stated in FSAR Section 9.3.3.The team determined that the licensees flood analysis did not account for a single failure of the level switches; therefore, the flood analysis did not evaluate the effects of flooding in the diagonal rooms of Units 1 and 2.As a result of the teams observations, the licensee completed Engineering Response, RER C091204801, Flooding of Torus Room and Diagonals, during the inspection. RERC091204801, determined that a main feedwater line break with a postulated single failure of: Unit 1 level switch (1T45-N007) would result in the loss of RCIC system, and Unit 2 level switches (2T45-N006 or 2T45-N007), would result in the loss of the HPCI system or RCIC systems. The licensee initiated CRs (2009105744, 2009105110,2009105111, 2009105615, and 2009105727) and administratively closed the AOVs as an interim compensatory measure. This issue is unresolved pending further inspection and interface with the licensee to determine the extent of condition and impact from the failure to scope and monitor the Reactor Building Equipment Drain Sump System in the licensees maintenance rule program, and the single failure design deficiency for the level switches. (URI 05000321/2009006-04 and 05000366/2009006-04, Reactor Building Equipment Drain Sump System for Units 1 and 2)
05000321/FIN-2009006-05	2009Q3	Hatch	Failure to Correctly Establish Acceptance Criteria for the Standby Diesel Service Water Pump Section	The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion XI, Test Control, for failure to correctly establish acceptance criteria for the Standby Diesel Service Water (SDSW) System. The licensee performed a past operability determination and initiated Condition Report (CR) 2009105651 to revise the acceptance criteria. The licensees failure to correctly establish acceptance criterion for the SDSW pump under the most limiting conditions was a performance deficiency. The finding is greater than minor because it adversely affected the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is of very low safety significance (Green) using the SDP because it did not represent a loss of system or safety function. A crosscutting aspect was not identified because the finding does not represent current performance.
05000390/FIN-2009002-02	2009Q1	Watts Bar	Acceptability of Plant Alterations Without NRC Submittal	A URI was identified following NRC review of a licensee decision not to provide a submittal in association with temporary alteration TACF 1-07-0002-065, implemented in March 2007 on the Emergency Gas Treatment System (EGTS). The temporary alteration (TACF 1-07-0002-065) changed the system start logic such that both trains would operate in automatic upon receiving the start signal. In their review of the licensees 10CFR50.59 evaluation, the inspectors found that the licensee had made a determination that no license amendment was required, though the supporting paragraph indicated a license amendment was appropriate and was to be accomplished in association with the licensees corrective action program (CAP). Upon further review, the inspectors determined that, as part of a 2005 functional evaluation, a single-failure vulnerability was determined to exist. That same evaluation also recognized that the dose consequence for the system, described in the UFSAR, was based on single fan operation. Given the calculation of record assumptions that all fan flow would be exhausted and the fact that both system fans could achieve flow via that path, the licensee determined that there was an increased beta dose consequence over that described in the UFSAR to Main Control Room operators. NUREG 0800, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants, limits beta dose in the control room to 30 rem. Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59, Section 4.3.3, states that the criterion for a more than minimal increase in consequence is greater than 10% of the margin to the limit. For this specific case, based on the UFSAR beta dose value of 6.803 rem, an increase of greater than 2.320 rem ((30 rem - 6.803 rem)*0.1) would indicate a more than minimal increase in the consequence. Using the licensee\'s re-evaluated beta dose value of 9.757 rem, the consequence difference was determined to be a 2.954 rem increase in beta dose for main control room operators, which exceeds the NEI 96-07 criterion for a more than minimal increase. The licensee\'s determination of the need for a license amendment was carried as an action item in PER 91670. Between 2005 and 2007 the licensee installed two temporary modifications to address the single-point failure vulnerability. The resulting configuration, at the time of inspection, did not resolve, nor compensate for the flow conditions which resulted in the licensees determination of the need for a submittal as of 2005. During the 2009 inspection, the inspectors found that no licensee amendment request had been submitted to the NRC to support changing the UFSAR while the calculations of record continued to indicate that one was warranted. This issue was unresolved pending additional NRC review to assess the adequacy of the licensees actions in response to the functional evaluation and the adequacy of 10 CFR 50.59 evaluations associated with the related temporary EGTS configuration modifications. This item is identified as URI 05000390/2009002-02: Acceptability of Plant Alterations Without NRC Submittal
05000390/FIN-2009002-04	2009Q1	Watts Bar	Licensee-Identified Violation	10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to this, on February 27, 2009, the lower containment particulate radiation monitor was returned to service with incorrect alarm setpoints which rendered the particulate radiation monitor inoperable. This was identified in the licensees CAP as PER 164765. This finding is of very low safety significance because other methods of reactor coolant system leak detection were available
05000390/FIN-2009002-01	2009Q1	Watts Bar	Auxiliary Feedwater System Compliance with General Design Criterion 2	The inspectors identified an unresolved item (URI) involving compliance of the AFW System with General Design Criterion 2. This URI will remain unresolved pending additional information from the licensee to determine if a violation of regulatory requirements occurred. On March 9-11, 2009, inspectors performed a routine inspection of the AFW system in accordance with Inspection Procedure 711111.04 Equipment Alignment. This inspection also used the insights gained in Operating Experience Smart Sample (OpESS) Negative Trend and Recurring Events Involving Feedwater Systems. During their review of operating experience, the inspectors noted that a failure of an AFW pumps had occurred at the Callaway Plant in 2002 due to debris generated from a degraded diaphragm in the condensate storage tank (CST). The inspectors examined system diagrams and confirmed that at Watts Bar there were no screens or other devices which would prevent debris from the CSTs from impacting the safety related auxiliary feed water pumps. The inspectors noted that the CSTs were not safety-related and were not protected from earthquakes or tornadoes. The inspectors also determined that the CSTs were lined with an epoxy phenolic coating which was routinely repaired during plant outages. However, if this coating became dislodged in sufficient quantities during normal operations or if an earthquake or other natural phenomena would cause CST debris, the AFW pumps could be adversely impacted. The UFSAR identified the AFW system as a safety-related system which is protected from the effects of natural phenomena. The UFSAR also stated that the plant complies with the requirements of General Design Criterion (GDC) 2, in that, structures, systems, and components important to safety shall be designed to withstand the effects of natural phenomena such as earthquakes, tornadoes, hurricanes and floods. Pending additional information from the licensee involving potential for CST debris and its impact on the AFW system and compliance with GDC 2, this item is identified as URI 050000390/2009002-01, Auxiliary Feedwater System Compliance with General Design Criterion 2
05000424/FIN-2008005-01	2008Q4	Vogtle	Unauthorized Entries Into High Radiation Areas	Two examples of a self-revealing non-cited violation of Technical Specification 5.7.1, High Radiation Area, was identified for unauthorized entry into High Radiation Areas (HRAs). Inadequate communication between workers and Health Physics department resulted in licensee personnel breaching HRA boundaries without prior knowledge of the radiological conditions. The licensee had entered these issues into the corrective action program as Condition Reports 2007105476 and 2007108830. This finding is greater than minor because it is associated with the Occupational Radiation Safety Cornerstone attribute of Human Performance and adversely affects the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. The finding was evaluated using the Occupational Radiation Safety Significance Determination Process and was determined to be of very low safety significance because it not related to As Low As Reasonably Achievable (ALARA) planning, did not involve an overexposure or substantial potential for overexposure, and the ability to assess dose was not compromised. This finding involved the cross-cutting aspect of Human Performance, Work Practices (H.4.a) because the HRA events were a direct result of poor communications during pre-job briefings and a willingness on the part of licensee personnel to proceed in the face of uncertainty. (Section 2OS1)
05000324/FIN-2008004-01	2008Q3	Brunswick	Licensee-Identified Violation	Technical Specification 5.4.1, Administrative Control (Procedures), requires that written procedures shall be established, implemented, and maintained covering applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972. Regulatory Guide 1.33, Section D (7) states, in part, that instructions for energizing, filling, venting, draining, startup, shutdown, and changing modes of operation should be prepared, as appropriate for the Emergency Core Cooling System. Contrary to the above, the licensees procedure OP-19, HPCI System Operating Procedure, Revision 112, was inadequate because it contained unclear actions which resulted in a main pump seal failure from an inadequate fill and vent of the Unit 1 HPCI system crossaround piping after a complete drain and refill during outage B117R1. On April 29, 2008, as a result of inadequate venting of the HPCI pump, the inboard seal failed. This issue is more than minor because it affects the Mitigating Systems Cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent core damage and is associated with the cornerstone attribute of equipment performance. This finding is of very low safety significance because the HPCI pump did not exceed its allowed TS outage time. This issue has been entered into the CAP as AR 277188
05000324/FIN-2008004-02	2008Q3	Brunswick	Licensee-Identified Violation	Technical Specification 5.4.1, Administrative Control (Procedures), requires that written procedures shall be established, implemented, and maintained covering applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972. Regulatory Guide 1.33, Section I (1) states that maintenance that can affect the performance of safety-related equipment should be properly preplanned, and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to the above, the licensees procedure 0CM-PHM504, Pacific Pumps, Model RHCH, HPCI main pump maintenance, Revision 7, was inadequate because the pump was reassembled with an improper clearance between the seal sleeve and seal plate bushing. On July 18, 2008, the main pump inboard seal failed due to excessive heating at the shaft sleeve due to contact between the seal plate bushing and the shaft sleeve such that the shaft sleeve set screw force applied to the shaft was relieved, and the pump internal pressure forced the seal sleeve out 1/8 inch. This 1/8 inch extension caused excessive force to be applied on the seal faces which resulted in premature failure due to seal face overheating followed by a quench. This issue is more than minor because it affects the Mitigating Systems Cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent core damage and is associated with the cornerstone attribute of equipment performance. This finding is of very low safety significance because the HPCI pump did not exceed its allowed TS outage time. This issue has been entered into the CAP as AR 287869
05000324/FIN-2008004-03	2008Q3	Brunswick	Licensee-Identified Violation	Technical Specification Limiting Condition for Operation 3.4.3, Safety/Relief Valves, requires 10 safety/relief valves to be operable while in Mode 1 with their lift setpoints within a specified range. Contrary to this, during surveillance testing on safety/relief valves removed from Unit 2 during the Spring 2007 refueling outage (B218R1), four of the eleven valves actuated at pressures outside the technical specification limits. This finding is of very low safety significance because the as-found lift setpoint conditions of the Unit 2 safety/relief valves were analyzed and determined to meet the design basis criteria for an over-pressurization event. This issue has been entered into the CAP as AR 287535
05000324/FIN-2008004-04	2008Q3	Brunswick	Licensee-Identified Violation	10 CFR 50.65(a)(4) states, in part, that before performing maintenance activities, the licensee shall assess and manage the risk that may result from the proposed maintenance activities. Contrary to the above, the licensee did not perform an adequate risk assessment of switchyard activities which involved operating a test device in the generator terminal current sensing circuitry in the switchyard relay house. Unit 2 automatically scrammed due to a spurious power load unbalance (PLU) turbine trip signal while the unit was in operation at 100% rated thermal power. This spurious signal was determined to be generated from the maintenance activities in the switchyard. The licensee determined that procedure 0AP-025 BNP Integrated Scheduling, which was used to implement Engineering Change, 68642, Digital Fault Recorder Replacement (Switchyard), did not adequately evaluate the post modification testing to be performed on the PLU circuit, and therefore did not characterize the maintenance as a contributor to the risk of a plant transient or reactor scram. The finding is of very low safety significance because the incremental core damage probability deficit is less than 1E-6 and the incremental large early release probability deficit is less than 1E-7. This issue has been entered into the CAP as AR 294164
05000424/FIN-2008003-02	2008Q2	Vogtle	Steam Generator Tube Damage as a Result of Tube Pulling Activities	An unresolved item (URI) was identified because additional information from the licensee is required to evaluate a potential finding regarding SG tube damage caused by tube pulling activities in SG 4. During Unit 1 spring 2008 outage, the licensee planned to remove two straight tube sections in SG 4, locations R11C62 and R12C98. The purpose of this activity was to study certain Eddy Current indications that were obtained in these locations and compare them with the actual tube material condition. When the removal of the tube section in location R11C62 was in process, the activity was interrupted when the pulling equipment slipped and the tube did not move further, indicating an unusual problem for this type of evolution. The vendor performing this activity conducted further investigation and determined that the tube had not been completely cut despite the procedural checks indicating a complete cut. As a result of this activity, several tubes adjacent to tube R11C62 suffered damage in the U-bend and 7th support plate areas. The damaged tubes were re-inspected with Eddy Current Testing, stabilized, and repaired by plugging. The licensee performed an Operational Assessment to evaluate the post repair condition of the SGs and determined that the repaired tubes, as well as the rest of the tubes left in service, will maintain their structural integrity until the next inspection opportunity. This issue is unresolved pending completion of NRC review and analysis of the final root cause evaluation and is identified as URI 05000424/2008003- 02, Steam Generator Tube Damage as a Result of Tube Pulling Activities.
05000400/FIN-2008006-01	2008Q2	Harris	Failure to Use Appropriate Acceptance Criteria for Testing Check Valves 1SW-9 and 10	The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XI, Test Control, for incorrect test acceptance criteria for Emergency Service Water (ESW) pump discharge check valves 1SW-9 and 10 during test procedure OST- 1214/1215, ESW System Operability Train A/B Quarterly Interval Modes 1-2-3-4-5-6- Defueled. This finding was entered into the licensees corrective action program as condition report NCR 277362. The procedure was immediately placed on hold and planned corrective actions included revision of the ESW pump test procedures to directly observe absence of reverse rotation of the ESW pumps to verify adequate performance of the ESW pump discharge check valves. This finding is more than minor because if left uncorrected, it would become a more significant safety concern since the test procedure could have allowed an inoperable check valve to satisfactorily pass surveillance testing. Specifically, test criteria established would not ensure that the safety objective of preventing pump reverse rotation was achieved. The inspectors assessed the finding using the SDP and determined that the finding was of very low safety significance (Green) because the deficiency did not result in the ESW pumps being inoperable. (Section 1R21.2.2
05000400/FIN-2008006-02	2008Q2	Harris	Failure to Correctly Translate Design Requirements Into Plant Construction Details of Masonry Block Walls	The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for failure to translate critical design attributes into drawings and the as-built condition of the plant. As a result, the fuel and air supplies to the emergency diesel generators (EDGs) were susceptible to risk from impingement due to potential structural failures of a wall for two external events, tornado and seismic. This finding is more than minor because it impacts the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems needed to mitigate the consequences of an accident. The inspectors assessed the finding using the SDP and determined that the finding was of very low safety significance (Green) because the deficiency, although sufficient to exceed the critical deflection limits and result in cracking, was analyzed to not result in catastrophic collapse. This issue is documented in the corrective action program as NCRs 276674, 277720, and 279326. (Section 1R21.2.9

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