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| Q | Significance | CCA | Identified by | Title | Description | |
|---|---|---|---|---|---|---|
| 05000338/FIN-2018003-01 | 2018Q3 | Green | Licensee-identified | Licensee-Identified Violation | This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2.a of the Enforcement Policy. Violation: TS 5.4.1.a, requires in part, that written procedures shall be established per Revision 2 of Regulatory Guide 1.33, Appendix A, of which part 9.a requires written procedures and documented instructions appropriate to the circumstances for performing maintenance that can affect the performance of safety related equipment. Contrary to the above, on June 12, 2018, the licensee failed to adequately establish a procedure appropriate to the circumstances during maintenance on the safety-related main control chillers. Specifically, licensee mechanical preventative maintenance procedure, 0-MPM-0806-02, Inspection of Control Room Chillers, Revision 0, did not provide a proper method to adequately monitor the Freon level in main control room chillers. Consequently, the licensee discovered a low Freon level condition on main control room chiller 1-HV-3-4B, which rendered the chiller inoperable. Significance: The inspectors reviewed Exhibit 2 Mitigating Systems Screening Questions of IMC 0609 Appendix A, The Significance Determination Process (SDP) for findings at Power and determined this finding was of very low safety significance, Green, because there was no design deficiency, it did not represent a loss of system or function, and did not represent an actual loss of function for greater than its TS allowed outage time. Corrective Action Reference: CR109958 | |
| 05000339/FIN-2018011-01 | 2018Q2 | Green | NRC identified | Failure to ensure compliance with the Technical Specification (TS) 5.4.1.a requirement relevant to procedures for plant fires | The NRC identified a Green finding and associated non-cited violation (NCV) of the TS 5.4.1.a requirement to establish and maintain fire contingency action procedures based upon the licensees failure to effectively perform reviews during the revisions of the procedures in accordance with procedure VPAP-0502, Procedure Process Control. The failure led to undetected errors and was a performance deficiency that was determined to be more than minor because, if left uncorrected, it could potentially lead to a more significant safety concern during Appendix R fire events. | |
| 05000338/FIN-2018001-01 | 2018Q1 | Green | Self-revealing | Failure to Assure Service Water Pump Sheds from Emergency Bus upon LOOP or SBO | A self-revealing Greennon-cited violation (NCV) of Technical Specification (TS)5.4.1.a, was identified for the licensees failure to have adequate written procedures for assuring proper configuration control in areas affected by maintenance or plant modifications. Specifically, the licensee failed to detect and correct a disconnected lead from contact C1 on 1-SW-62-1SWEB03. This directly led to the failure of the 1B service water (SW) pump to shed from the 1J emergency bus during performance of maintenance procedure 1-PT-83.2 on March 11, 2018. | |
| 05000338/FIN-2017403-01 | 2017Q4 | Green | H.1 | NRC identified | Security | |
| 05000338/FIN-2017003-01 | 2017Q3 | Green | H.1 | Licensee-identified | Licensee-Identified Violation | TS 5.4.1 requires, that Written procedures shall be established, implemented, and maintained covering the following activities: a. The applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide (RG) 1.33, Appendix A, identifies Access control to radiation areas, including a Radiation Work Permit (RWP) system as one of the areas requiring procedural controls. Additionally, procedure VPAP-2101, Radiation Protection Program, Revision 35, Attachment 1, RCA Work Practices, identifies what workers should know prior to entering the RCA (minimum requirements). Attachment 1 states, in part, All workers entering the RCA are required to: 1) Notify RP prior to entering the RCA. Contrary to the above requirements, on September 15, 2017, two maintenance workers entered U2 Containment, a posted High Radiation Area (HRA), while signed in on an incorrect RWP, and without checking in at the Health Physics Shift Supervisor window prior to entering containment. The workers signed in on the RWP they had used earlier in the day which did not allow entry into a HRA. The containment building had been posted as a HRA in preparation for lifting the reactor head while the workers were out of containment. HP personnel in the remote monitoring facility identified that the individuals were on an incorrect RWP, informed HP personnel in containment, and the workers exited containment prior to the head lift. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure and the licensees ability to assess dose was not compromised. The immediate corrective actions were documented in CR 1078223. Corrective actions included a human performance review, coaching of the individuals by RP Management, and distribution of a site-wide message discussing the incident and reminding site personnel to remain aware of radiological safety. |
| 05000338/FIN-2017007-01 | 2017Q2 | Green | NRC identified | Failure to Qualify MCCs in Cable Penetration areas in accordance with 10 CFR 50.49 | The NRC identified a Green non-cited violation of 10 CFR 50.49(e)(5) for failing to base the qualified life of structures, systems, and components (SSCs) (i.e. Nordel O-rings) on the known limits of extrapolation in accordance with IEEE 323 Sections 6.5.3, Extrapolation, and 6.5.4 Determination of Qualification. In response, the licensee determined that the affected components remained operable because the age of the O-rings in question was within the original qualification. The licensee entered this into their corrective action program as CR 1065957. The performance deficiency was determined to be more than minor because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, the failure to properly determine the qualified life and replace the O-rings at the required time interval would adversely affect the reliability of that equipment when called upon to respond to initiating events and prevent undesirable consequences. This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance. | |
| 05000338/FIN-2017007-02 | 2017Q2 | Green | NRC identified | Failure to Qualify EGS Quick Disconnects in Accordance With IEEE Std. 323-1974 | The NRC identified a Green non-cited violation of 10 CFR 50.49(f) for failing to qualify structures, systems, and components (SSCs) (eight motor control centers) located in a radiation harsh environment in accordance with IEEE Std. 323-1974 Section 5, Principles of Qualification. In response to this issue, the licensee performed an operability determination and determined that the motor control centers (MCCs) were operable based on the material similarity of the original SSCs and the new SSCs. This issue has been entered into the corrective action program as CR 1065894 The performance deficiency was determined to be more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of the safety related AC Power System. Specifically, the failure to perform environmental qualification for SSCs subject to a harsh environment, during which they must perform a safety function adversely affected the reliability of that equipment when called upon. This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance. | |
| 05000338/FIN-2017007-03 | 2017Q2 | Severity level IV | NRC identified | Failure to Obtain NRC Review and Approval for Changes to Safety-Related Dike West of Unit 2 Turbine Building | The team identified a Severity Level IV non-cited violation of 10 CFR 50.59(c)(2), Changes, Tests, and Experiments, for the licensees failure to obtain a license amendment, as specified by Nuclear Energy Institute (NEI) 96-07 Section, 4.3.2, prior to implementing a change that increased the likelihood of a malfunction of a safety-related dike. This has been entered into the licensee corrective action program as condition report 1065945. The violation was dispositioned using the traditional enforcement process in accordance with the NRC Enforcement Policy, Subsection 2.2.2 Revised August 1, 2016, because the issue affected the NRCs ability to perform its regulatory oversight function. The NRC Enforcement Policy, Section 6.1, Violation Examples for Reactor Operations, Subsection 6.1.d.2 specified that violations of 10 CFR 50.59 which resulted in conditions that were evaluated by the Significance Determination Process (SDP) as being of very low safety significance represented a severity level IV violation. The regional senior reactor analyst performed a screening analysis to determine the significance of the violation. Using very conservative failure frequencies for ductile iron pipe used in water systems, and a conservative initiating event frequency for an independent simultaneous rainfall capable of filling the dike, the finding was determined to be of very low safety significance. The inspector determined that the detailed risk evaluation confirmed that a severity level IV violation was appropriate. Crosscutting aspects are not assigned to traditional enforcement violations. | |
| 05000338/FIN-2017001-02 | 2017Q1 | Green | Self-revealing | Chemical Addition System Outside of Technical Specification Due to Excessive Unseating Thrust on MOVs | a. Inspection Scope The LER documented that North Anna failed to maintain the full design bases functionality of its Sodium Hydroxide (NAOH) injection for both units as required by TS 3.6.8. The inspectors reviewed the LER and the associated corrective action document (CR 1029674) to verify the accuracy and completeness of the LER and the appropriateness of the licensees corrective actions. The inspectors also reviewed the LER and CR to identify any licensee performance deficiencies associated with the issue. b. Findings Description: On March 9, 2016, with Unit 1 (U1) at 100 percent power in Mode 1 and Unit 2 (U2) in Mode 6 for a scheduled refueling outage, 2-QS-MOV-202B failed to stroke open during testing due to excess unseating thrust. An extent of condition review and engineering evaluation determined that 2-QS-MOV-202A maintained its safety function. An extent of condition review and engineering evaluation of the U1 valves determined that 1-QS-MOV-102B maintained its function but 1-QS-MOV-102A did not. While only one of the valves is needed in order for the system to perform its safety function, TS 3.6.8 requires both valves to function in order to be considered operable. A failure of these valves would result in a loss of redundant safety function and inability to perform an emergency operating procedure or to prevent mitigating the consequences of accidents that would result in potential offsite exposure in excess of 10 CFR Part 100 limits. These valves were originally installed in September 2010 (U1) and September 2011 (U2). These valves are stroked every refueling outage per the IST and monitored by the motor operated valve (MOV) program every six refueling outages. The licensees investigation determined that all appropriate testing per the MOV program and design changes have been applied. No previous failure of these valves were identified. No human errors were found during initial valve set up or maintenance and no design errors were identified. The licensees apparent cause evaluation (ACE) concluded that the cause of 2-QS-MOV-202B exhibiting excessive unseating thrust, resulting in a failure to open during functional testing, was due to mechanical binding internal to the valve body and/or actuator. This was also considered to be the cause for the excessive unseating thrust exhibited in 1-QS-MOV-102A. Valves 2-QS-MOV-202A and 1-QS-MOV-102B also exhibited mechanical binding, but not to the same degree and did not fail. The licensee implemented corrective actions to ensure the chemical addition tank isolation MOVs do not bind again, Design Changes (DC NA-16-00023 for U1 and DC NA-16-00021 for U2) were implemented to change the actuator gear set to provide more unseating capability for the valves. In addition, the valve stroke was changed to position limit switch controlled verses torque controlled seating, allowing valve seating to be adjusted to lighter loads providing even more margin. As an interim compensatory measure, these valves will be stroked every six months in addition to every cold shutdown. Stroking the valves verifies capability and reduces the pull-out-force required for the next stroke. Valve stroke frequency will be reviewed based on data collection and may support revision to the operability determination currently in place for Units 1 and 2. Based on review of the licensees ACE, the historical industry operating experiences, and previous MOV test data and IST stroke time data, the inspectors determined that there was no performance deficiency associated with this issue because the cause of failed the TS surveillance tests was not reasonably within the licensees ability to foresee and correct. Enforcement: The inspectors determined a violation of TS occurred because of failure to maintain the full design basis functionality of the Chemical Addition System. North Anna TS Limiting Condition for Operation (LCO) 3.6.8 requires the Chemical Addition System to be operable when in Modes 1, 2, 3 and 4. The associated action statement requires, in part, that with the Chemical Addition System inoperable, Restore Chemical Addition System to OPERABLE status within 72 hours and if Required Action and associated Completion Time is not met, the unit be in Hot Standby within 6 hours and in Cold Shutdown within 84 hours. Contrary to the above, on March 9, 2016, the licensee determined that the Chemical Addition System was inoperable on U1 for more than 72 hours while the unit was in Modes 1, 2, 3 and 4; and U1 was not placed in Hot Standby within 6 hours and in Cold shutdown within 84 hours. Later, through an extent of condition review, the licensee concluded that the U2 Chemical Addition System was also inoperable. Although a violation of the TS occurred, the violation was not reasonably foreseeable and preventable by the licensees QA measures or management controls. Therefore, the violation of TS 3.6.8 was not associated with a licensee performance deficiency. The inspectors concluded that the violation would normally be considered at Severity Level III in accordance with Enforcement Policy section 6.1.c. However, the inspectors utilized available risk-informed tools to more accurately assess the safety significance of this issue. Since the chemical addition system is considered a part of containment system, the inspectors evaluated this issue in accordance Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016 and the finding was determined to adversely affect the Barrier Integrity Cornerstone. The inspectors screened the finding using Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that the finding screened as low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.), containment isolation system (logic and instrumentation), and heat removal components; and it did not involve an actual reduction in function of hydrogen igniters in the reactor containment. This issue represented a degradation of the radiological barrier function provided for the reactor building. However, because the violation was not associated with a licensee performance deficiency and it was not avoidable by reasonable licensee QA measures or management controls, the NRC is exercising enforcement discretion (EA-17-007) in accordance with Section 3.10 of the Enforcement Policy. The violation will not be considered in the assessment process or the NRCs Action Matrix. This issue was documented in the licensees corrective action program as CR1029674. | |
| 05000339/FIN-2017001-01 | 2017Q1 | Green | H.5 | Self-revealing | Inadequate Design Control of 2 -RC- P-1C Piping Supports | Green . A self -revealing Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for the failure to correctly translate applicable regulatory requirements and the design basis into specifications, drawings, procedures, and instructions . Specifically, the licensee failed to include the pipe support (2 -FPH -CH- 416- 11) in the scope of design change (DC) NA -13- 01059, Unit 2 Reactor Coolant Pump Seal Replacement, which resulted in a large mean stress on the socket weld due to the 1.5- inch controlled bleed- off line piping not being properly aligned in the downstream pipe support, and therefore not allowing for the thermal growth of the reactor coolant system (RCS). As a result of the large mean stress, a crack initiated at a small defect (lack of fusion) in the toe of the socket weld and propagated through the weld due to normal cyclic vibration from the Unit 2 C reactor coolant pump (RCP). This finding was entered into the licensee's corrective action program as Condition Report (CR) 1043540. The finding was more than minor because it was associated with the design control attribute of the Initiating Events and Barrier Integrity cornerstones and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radio- nuclide releases caused by accidents or events. Specifically, the inadequate design control of the piping support following Unit 2 RCP Seal Replacement resulted in an un-isolable through wall leak in the controlled bleed- off line piping and was identified as RCS pressure boundary leakage. The inspectors evaluated the finding in accordance with Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016, and the inspectors screened the finding using Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination Process (SDP) for Findings at -Power, dated June 19, 2012. The finding screened out in the review of the Barrier Integrity cornerstone as the performance deficiency ( PD ) was not related to pressurized thermal shock ; therefore , the finding will be addressed under the Initiating Events cornerstone. Since the issue affected multiple cornerstones and because the licensee classified the leakage as RCS pressure boundary leakage, the NRC performed a detailed risk evaluation for the PD. The detailed risk evaluation was performed by a regional SRA in accordance with the NRC IMC 0609 Appendix A utilizing the NRC North Anna SPAR model. The PD was modeled as an increase in the small loss of coolant accident frequency given a failure of the RCP seal. The dominant sequence was a rupture in the controlled bleed off line leading to a small loss of coolant accident due to RCP seal failure with failure of 3 containment sump recirculation leading to loss of core heat removal and core damage. The risk was mitigated by the RCP seal failure probability and the remaining mitigation. The detailed risk evaluation estimated that the PD resulted in an increase in core damage frequency of < 1.0 E -6/year, a GREEN finding of very low safety significance. The finding had a cross -cutting aspect in the area of human performance, work management H.5, because the licensee failed to include the pipe support (2-FPH -CH- 416 -11) in the scope of the design change by engineering information bulletin (EIB) # N10 -002 requirements |
| 05000338/FIN-2016002-03 | 2016Q2 | Green | Licensee-identified | Licensee-Identified Violation | 10 CFR Part 50.65 section (a)(2) requires, in part, that the performance or condition of a structure, system, or component is being effectively controlled through the performance of appropriate preventative maintenance, such that the structure, system, or component remains capable of performing its intended function. In accordance with this requirement, the licensee established procedure ER-AA-MRL-100, Implementing Maintenance Rule, to consistently apply requirements. One requirements of ER-AA-MRL-100 is monitoring equipment unavailability or out-of-service time on a rolling 12 month average. The allowed unavailability time for each charging pump is 438 hours. Contrary to the established goals, on May 5, 2016, the licensee identified Unit 1 C charging pump, 1-CH-P-1C, has accrued 517.3 hours of unavailability and Unit 2 C charging pump, 2-CH-P-1C, has accrued 588.0 hours of unavailability. By exceeding the established unavailability hour goals, licensee failed to control the condition of 1-CH-P-1C and 2-CH-P-1C to ensure the component remains capable of performing its intended function. Subsequently, both charging pumps are being evaluated under 10 CFR Part 50.65 (a)(1) for failure to meet established unavailability goals. The licensees failure to control the condition of 1-CH-P-1C and 2-CH-P-1C to ensure the components remained capable of performing their intended function was a PD. The PD was more than minor because it was associated with 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 inspectors performed the significance determination for the finding using NRC Inspection Manual Chapter 0609, Appendix A, Attachment 2, dated July 1, 2012 and determined the risk significance was very low (GREEN), because the charging system maintained operability in accordance with TS. The licensee entered this condition into their CAP as CR1036685 and CR1036687. | |
| 05000339/FIN-2016002-02 | 2016Q2 | Green | NRC identified | Adequacy of Class 1E 120VAC Vital Bus Design | The NRC identified an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the adequacy of design for the protection devices at the 120VAC vital instrumentation buses. Specifically, the licensees failure to verify that the protective devices at the Unit 1 and Unit 2 120VAC vital instrumentation buses would isolate failed equipment when supplied by the voltage regulating transformer in accordance with IEEE 308-1971 was a PD. The licensee entered this issue into their CAP as CRs 1006865 and 1013278. At the time of the inspection, the licensee was evaluating the issue to determine appropriate corrective actions. This does not present an immediate safety concern because the performance deficiency is related to a non-conformance with a design standard upon which only one train would be affected by a postulated single failure and the other train would remain available and capable to respond to the design basis accident. The performance deficiency was determined to be more than minor because it adversely affected the Design Control 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, failing to isolate failed equipment could lead to tripping the associated 120VAC vital bus, causing unnecessary loss of other safety related equipment connected to the bus. The finding was determined to be of very low safety significance (Green), because it was a deficiency affecting the design or qualification of a structure, system, or component (SSC) and the SSC maintained its operability. This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance. | |
| 05000338/FIN-2016002-01 | 2016Q2 | Green | H.14 | NRC identified | Inadequate Translation of Design Calculations into Compensatory Measures when Removing Missile Barriers Could Result in EDGs and SBO Diesel Inoperable | The NRC identified an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the inadequate translation of design calculations into compensatory measures when removing missile barriers. The inadequate translation of design calculations into compensatory measures when removing required passive missile shields is a performance deficiency (PD). The PD was more than minor because it was associated with the human performance attribute of the Mitigating System cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the inadequate compensatory measure resulted in the licensee having to make required changes to the compensatory measures in order to resolve missile protection concerns. The inspectors performed the initial significance determination for the finding using NRC Inspection Manual Chapter 0609, Appendix A, Exhibit 4, External Events Screening Questions, dated July 1, 2012. The finding required a detailed risk evaluation because the safety function of the onsite emergency diesel generators (EDGs) and the function of the station blackout (SBO) diesel were assumed to be completely failed due to inadequate compensatory missile protection measures for a high wind event. The finding has a cross-cutting aspect in the area of human performance associated with the conservative bias attribute because individuals use decision making-practices that emphasize prudent choices over those that are simply allowable. A proposed action is determined to be safe in order to proceed, rather that unsafe in order to stop (H.14). The licensee entered this issue into the corrective action program (CAP) as Condition Report (CR)1034958. |
| 05000338/FIN-2015004-02 | 2015Q4 | Green | Licensee-identified | Licensee-Identified Violation | NUREG 1022, Event Reporting Guidelines 50.72 and 50.73, Revision 3, section 3.2.4 and 3.2.7, cover degraded or unanalyzed conditions and an event or condition where structures, components, or trains of a safety system could have failed to perform their intended safety function as described in the plant safety analysis. Contrary to this, on October 7, 2015, the licensee failed to ensure the ESGR door was fully latched. As a result, when security personnel conducted their periodic rounds, the ESGR door, a HELB boundary, was determined to not be fully latched for approximately 46 minutes. The night shift operating crew failed to review the reportability for a HELB boundary not being met. The dayshift operating crew made the required 8 hour report to the NRC Headquarters Operations Center at 1823 on October 8, 2015. The inspectors determined that the failure to submit a report required by 10 CFR 50.72 for the unanalyzed condition described above had the potential to impact the regulatory process based, in part, on the information that 10 CFR 50.72 reporting serves. Since the issue impacted the regulatory process, it was dispositioned through the Traditional Enforcement process. The inspectors determined that this issue was a Severity Level IV violation based on Example 6.9.d.9 in the NRC Enforcement Policy. Example 6.9.d.9 specifically states, A licensee fails to make a report required by 10 CFR 50.72 or 10 CFR 50.73. This issue was entered into the licensees CAP as CR1012468. | |
| 05000338/FIN-2015008-03 | 2015Q4 | Green | H.4 | NRC identified | Failure to Ensure that the Turbine-driven Auxiliary Feed Water Pump had the Capability to Provide Sufficient Flow Such that Residual Heat Removal Entry Conditions Could Be Achieved during Fire Event | The inspectors identified a Green non-cited violation (NCV) of North Anna Power Station, Units No.1 and No. 2, Renewed Facility Operating License, Conditions 2.D, Fire Protection, for the licensees failure to ensure that the turbinedriven auxiliary feed water (AFW) pump had the capability to provide sufficient flow such that residual heat removal (RHR) entry conditions could be achieved during fire events. The licensee entered this issue in their corrective action program as CR 1017291 with an action to re-evaluate the capability of the TDAFW pumps to achieve RHR entry conditions. The sites failure to provide reasonable assurance that the turbine-driven AFW pump had the capability to provide sufficient flow such that RHR entry conditions could be met was a performance deficiency. This performance deficiency was more than minor because it was associated with the design control attribute of the reactor safety mitigating systems cornerstone and it affected the cornerstone objective of protection against external events (i.e., fire). The performance deficiency adversely affected the sites capability to achieve cold shutdown conditions in 72 hours for a fire event. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.3.1, Question A because the issue was associated with achieving cold shutdown conditions. The inspectors determined that the performance deficiency had a cross-cutting aspect of Teamwork in the Human Performance area (H.4). |
| 05000338/FIN-2015004-03 | 2015Q4 | Green | Licensee-identified | Licensee-Identified Violation | Procedure CM-AA-FPA-100, Fire Protection/Appendix R (Fire Safe Shutdown) Program, Revision 10, Attachment 2, Section 3.12, step n.1 states, Fire doors must be closed and latched at all times. Contrary to Section 3.12, step n.1 of CM-AA-FPA-100, the licensee failed to ensure the fire door to the ESGR was closed and latched at all times. Specifically, on October 7, 2015, when security personnel conducted their periodic round, the ESGR door, a fire boundary, was found to not be fully latched. The ESGR door, a HELB boundary, was determined to not be fully latched for approximately 46 minutes. This finding was identified by the license and entered in the licensees corrective action program as CR1012468. The inspectors performed a significance determination using NRC Inspection Manual 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 dated July 1, 2012. Because the Transient Initiator was a HELB that would impact both trains of mitigation equipment required to transition the plant to a stable shutdown condition, a detailed risk evaluation was required. A bounding risk evaluation was performed by a regional SRA which assumed that all pipe failures in turbine building high energy lines with enough energy to create a harsh environment would lead to failure of all equipment within the ESGR and result in a conditional core damage probability of 1.0. The systems considered were main steam, main steam drain, auxiliary steam, extraction steam, low pressure steam, blowdown, feedpump discharge and feedpump recirculation piping. Pipe mean failure rate data from EPRI report 102186 was used. No isolation of the pipe ruptures were assumed and no credit was allowed for operations to realize that a HELB had occurred and for closing the door. An exposure period of 46 minutes was utilized. The phase 3 SDP risk assessment determined the risk of the performance deficiency was an increase in core damage frequency of <1E-6, very low safety significance (Green). The short exposure period mitigated the risk of the performance deficiency. | |
| 05000338/FIN-2015008-02 | 2015Q4 | NRC identified | ECST Level Indication/Setpoints and Associated Operator Action that Ensures the Auxiliary Feedwater Pumps have an Adequate Suction Source | The inspectors identified an Unresolved Item (URI) associated with the emergency condensate storage tank (ECST) level indication/setpoints and associated operator actions that ensures the auxiliary feedwater (AFW) pumps have an adequate suction source. UFSAR, Section 7.4-2, states that the emergency condensate storage tank (ECST) was designed to supply the initial eight hours of water to the auxiliary feedwater (AFW) pumps during licensing bases events. The inspectors noted that the licensee utilized operator actions to reduce AFW flow during the initial stages of events which is typically accomplished in order to prevent over cooling of the primary RCS during events where maximum AFW is not required. For events where maximum AFW may be required, the licensee developed calculations to ensure that an adequate water supply was maintained. The licensees Calculation ME-0584, Maximum AFW Pump Flow and NPSH Analysis, (dated 11/04/1999) determined that AFW flow reduction was required within the initial 30 minutes of an event to ensure that the pumps had sufficient net positive suction head. The inspectors determined, in some cases, that operator actions would be required prior to the receipt of the ECST tank level alarm that was described UFSAR Section 10.4.3.3, which stated that the ECST had redundant ECST safety-level alarms (1/2-CN-LI-200A and -200B) to alert operators that sufficient inventory remained for 20 minutes of pump operation at the highest-volume flow rates. Additionally, the inspectors noted that a Virginia Electric Power Company letter, dated December 22, 1999, stated that Technical Specifications ensure that the level maintained in the ECST is adequate to mitigate the accident without operator action during a design basis accident. Therefore, the indication of ECST level is not required as a Type A variable. Indication of ECST level remains a Type D, Category 1 variable... This issue is unresolved pending the NRCs review of applicable licensing requirements, calculations, and operating procedures to assess the adequacy of the ECST level indication/setpoints and associated operator actions to ensure that the AFW pumps have an adequate suction source as described by their licensing design basis. This issue is identified as URI 05000338 & 05000339/2015008-02, ECST Level Indication/Setpoints and Associated Operator Action that Ensures the Auxiliary Feedwater Pumps have an Adequate Suction Source. | ||
| 05000338/FIN-2015008-01 | 2015Q4 | Green | NRC identified | Inadequate Procedural Guidance for Implementing Alternative Shutdown for a Fire in the Unit 2 Quench Spray Pump House | The inspectors identified a Green non-cited violation (NCV) of Technical Specification 5.4.1.a, for the licensees failure to provide adequate procedural guidance for implementation of the alternative shutdown capability in the event of a fire in the quench spray pump house. In particular, the fire safe shutdown procedure did not include actions to locally fail open the Unit 2 turbine-driven auxiliary feedwater (TDAFW) pump steam admission valves to allow operation of the TDAFW pump in the event the motor driven auxiliary feedwater pumps (MDAFW) were adversely affected by fire damage. The licensee entered this issue in their corrective action program as CR 1017083 and established compensatory actions until the Unit 1 and 2 procedures were revised. The sites failure to maintain adequate procedural guidance to operate the Unit 2 TDAFW pump for a fire in the quench spray pump house was determined to be a performance deficiency. This performance deficiency was more than minor because it was associated with the procedure quality attribute of the reactor safety mitigating systems cornerstone and it affected the cornerstone objective of protection against external events (i.e., fire). The inadequate procedural guidance affected the fire protection defense-in-depth element involving safe shutdown of the reactor. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.3.1, Question A, based upon observations that there were no credible fire scenarios which would likely result in simultaneous fire damage to the cables for the Unit 2 TDAFW pump and both Unit 2 MDAFW pumps. No cross-cutting aspect was identified because the issue was determined to not reflect current licensee performance. | |
| 05000338/FIN-2015004-01 | 2015Q4 | Green | H.5 | Self-revealing | Failure to Follow Foreign Material Exclusion Procedure | A self-revealing, Green NCV of TS 5.4.1.a, "Procedures," as required by Regulatory Guide 1.33, Revision 2, Appendix A, Section 9a, Procedures for Performing Maintenance, was identified for inadequate implementation of licensee procedure MA-AA-102, Attachment 4, "Foreign Material Exclusion," Part D Closeout Inspections Revision 15, which resulted in foreign material intrusion into the B SW return header The licensee has entered this issue into their corrective action program as CR1010424. The inspectors identified a performance deficiency (PD) for the failure to adequately implement the foreign material exclusion maintenance procedure MA-AA-102, Attachment 4, "Foreign Material Exclusion," Part D Closeout Inspections Revision 15. The inspectors determined that the PD was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences, (i.e., core damage). Specifically, the inadequate FME closeout led to foreign material intrusion into the B SW return header when maintenance materials, such as plastic bags and mop heads, were not removed and made their way into the B SW return header. The inspectors used Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and determined that the finding was of very low safety significance or Green because the B SW return header did not have an actual loss of safety function for greater than its allowed outage time (7 days). The finding had a cross-cutting aspect in the area of Human Performance, Work Management component, because licensee personnel did not follow procedure requirements of MA-AA-102, Attachment 4, "Foreign Material Exclusion," Part D Closeout Inspections Revision 15 during the return to service portion of the work activity for the B SW return header. |
| 05000338/FIN-2015007-01 | 2015Q3 | NRC identified | Adequacy of Class 1E 120VAC Vital Bus Design | Calculation 14258.79-E-4, Short Circuit Currents 120V AC Vital Buses and Miscellaneous Circuits Appendix R Evaluation, Rev.1, Addendum C, stated that the maximum short circuit available to the 120VAC vital buses from the Units 1 and 2 20KVA inverters was 200% of rated full load current, equaling 334A, and 175% of full rated current, equaling 365A, when supplied by the 25KVA voltage regulating transformer. These values were input into Technical Report EE-0118, 10 CFR Part 50 Appendix R Electrical Distribution System Coordination Study, Rev. 2, to verify proper breaker coordination for the 120 VAC Vital instrumentation buses. In 2003, the licensee received concurrence from the vital inverter vendor stating that while the steady state short circuit current limit was indeed approximately 200% of rated full load current for the inverter, the steady state short circuit current was approximately 200% of rated full load current for the regulating transformer, which was different than what was assumed in the technical report. The memo also stated that the 12 cycle instantaneous fault current for the inverter and regulating transformer would be approximately 500% of rated full load current, equaling 833A and 1042A for the inverter and transformer respectively. These values were not evaluated in the technical report. The team noticed that when the 120VAC instrument buses were supplied by the regulating transformer, a condition allowed by TS, breaker coordination could not be verified for the 120VAC buses based on the instantaneous fault values concurred on by the vendor. Specifically, coordination could not be verified for the breakers associated with the 1-I and 2-I 120VAC buses. TS 3.8.7 allows the regulating transformer to supply the vital buses for <=24 hours while the batteries are being equalized and TS 3.8.9 allows the licensee to consider the vital buses operable while they are energized from this transformer. The team was concerned that TS could allow the licensee to be on the regulating transformer when coordination could not be verified for the 120VAC buses. The lack of breaker coordination could result in the loss of additional engineered safety features during a design bases event. The licensee entered this issue into their corrective action program as CR1006865. This issue is a URI pending the determination of whether a violation of NRC requirements exists. | ||
| 05000338/FIN-2015003-01 | 2015Q3 | Green | Licensee-identified | Licensee-Identified Violation | The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, being for dispositioned as a NCV: Technical Specification (TS) 3.7.5 for Auxiliary Feedwater System requires that three AFW trains be operable in Modes 1, 2, and 3. TS Action C.1 also requires that if two AFW trains are inoperable in Modes 1, 2, or 3, a required action places both units in Mode 3 within 6 hours. Contrary to the above, on May 8, 2015, the licensee discovered that two motor-driven AFW (MDAFW) trains were inoperable for more than 12.5 hours and TS Action C.1 was not completed. Using Manual Chapter 0609, Attachment 4, Initial Characterizations of Findings, Table 2, dated July 1, 2012 and Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, Exhibit 2, dated July 1, 2012, the inspectors determined a detailed risk evaluation was required because the finding represented both MDAFW out of service exceeding its allowed outage. A Detailed SDP risk evaluation was performed by a regional SRA in accordance with the guidance of NRC IMC 0609, Appendix A, using the latest NRC North Anna SPAR risk model. The major analysis assumptions included: a one day exposure period, both MDAFW pumps assumed to fail to run with no ventilation available, and no recovery credit applied, for a twenty four hour mission time. A sensitivity analysis was run with a seven day mission time and recovery credit allowed. Both analyses determined the increase in CDF due to the performance deficiency was < 1.0E-6/year a GREEN finding of very low safety significance. The dominant sequence for both analyses was a Reactor Trip Initiator with a Loss of the Condenser Heat Sink (IE-LOCHS), failure of Main Feedwater (MFW), failure of AFW, and failure of the operator to implement Feed and Bleed cooling leading to core damage. MFW was failed due to loss of condensate. MDAFW was failed due to the PD and the Turbine Driven AFW (TDAFW) was a random failure to run. The risk was mitigated by the availability of TDAFW and the short exposure period. This issue was entered into the licensees CAP as CR579372, and resulted in Apparent Cause Evaluation, ACE19928, that determined additional training was required for licensee personnel to develop sensitivity to auxiliary equipment required to maintain operability of safety related systems that is not specifically mentioned in the Technical Specifications. | |
| 05000338/FIN-2015003-02 | 2015Q3 | Green | NRC identified | Technical Specification (TS) Required Shutdown due to Reactor Coolant System Pressure Boundary Leakag | A violation of TS occurred because it constituted pressure boundary leakage. North Anna TS Limiting Condition for Operation (LCO) 3.4.13.a requires, in part, that RCS leakage be limited to No PRESSURE BOUNDARY LEAKAGE, when in Modes 1, 2, 3 and 4. The associated action statement requires, in part, that with any (RCS) pressure boundary leakage, the unit be in Hot Standby within 6 hours and in Cold Shutdown within the following 36 hours. Contrary to the above, on December 23, 2014, it was discovered that RCS pressure boundary leakage did exist while the unit was in Modes 1, 2, 3 and 4; and that the unit was not placed in Hot Standby within 6 hours and in Cold shutdown within the following 36 hours. Although a violation of the TS occurred, the violation was not attributable to an equipment failure that was avoidable by reasonable licensee quality assurance measures or management controls. Therefore, the violation of TS 3.4.13.a was not associated with a licensee performance deficiency. The inspectors concluded that the violation would normally be characterized as Severity Level III in accordance with Enforcement Policy section 6.1.c. However, because the violation was not associated with a licensee performance deficiency and it was not avoidable by reasonable licensee QA measures or management controls, enforcement discretion (Enforcement Action (EA)-15-120) in accordance with Section 2.2.4.d and 3.5 of the Enforcement Policy was provided. The violation will not be considered in the assessment process or the NRCs Action Matrix. This issue was documented in the licensees corrective action program as CR568000. Licensee corrective actions included the following: Performed an extent of condition NDE of all three cold leg loop drain lines for Unit 1. Results indicated low level craze cracking and a circumferential defect in the similar elbow on C drain loop piping. No issues were found in the A drain loop piping. Replaced the cracked elbow from the B loop drain piping. Provided the failed B loop elbow/piping for materials failure analysis. The results of the evaluation are being used to confirm the direct cause of thermal fatigue and provide more insight on the failure mechanism. Performed an evaluation in accordance with ASME Section XI Sub-article IWB- 3640, Evaluation Procedures and Acceptance Criteria for Austenitic Piping, of the Unit 1 C loop drain elbow. The results determined that it was acceptable to operate the unit until the Spring 2015 Refueling Outage (RFO), during which, the repairs were made. Discontinued taking RCS cold leg (Tc) chemistry samples. RCS chemistry samples are currently being taken from the hot leg (Th). Informed the EPRI Materials Reliability Program of this failure, and continue to work with the industry on this and similar issues. | |
| 05000338/FIN-2015405-01 | 2015Q3 | Green | NRC identified | Security | ||
| 05000338/FIN-2015405-02 | 2015Q3 | Green | NRC identified | Security | ||
| 05000338/FIN-2015007-02 | 2015Q3 | Green | NRC identified | Failure to Consider Potential Water Hammer Impact Loading on AFW piping | The team identified a non-cited violation (NCV) of 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to control deviations from their piping design code of record for the auxiliary feedwater (AFW) system discharge lines. The licensee failed to consider the impact forces from a potential water hammer event as required by USA Standard (USAS) B31.1.0. The licensee entered this issue into their corrective action program as CR1003896. The licensee measured the discharge line temperatures of the AFW system to verify that current seat leakage past the check valves did not support steam void formation based on the recorded temperature and pressure in the discharge line such that water hammer was avoided. Additionally, the licensee implemented weekly temperature monitoring for continued operability of the AFW discharge lines in CA3003072. This performance deficiency was more than minor because it was associated with the mitigating systems cornerstone attribute of design control and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not ensure the capability of the AFW piping because they did not consider that an undiscovered steam pocket in any of the AFW pumps discharge lines could lead to a water hammer in the line when AFW is initiated during an event. The team used IMC 0609, Att. 4, Initial Characterization of Findings, issued June 19, 2012, for Mitigating Systems, and IMC 0609, App. A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design of a mitigating structure, system, or component (SSC), and the SSC maintained its operability or functionality (as shown through review of documentation related to prior identified leakage). The team determined that no cross-cutting aspect was applicable because the finding was not indicative of current licensee performance. | |
| 05000338/FIN-2015002-01 | 2015Q2 | Green | H.1 | Self-revealing | Failure To Maintain An Adequate Maintenance Procedure For The Turbine Driven Auxiliary Feedwater Pump | Green. A self-revealing NCV of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to maintain an adequate maintenance procedure to set the governor valve on the Unit 1 Turbine Driven Auxiliary Feedwater (TDAFW) pump to the fully closed position. Specifically, the licensee failed to clarify key measurements in Maintenance Procedure 0-MCM-0412-02, Repair of the Terry Turbine Governor Valve, Revision 11, section 6.4.6, which sets the fully closed position of the governor valve that also adversely impacted the performance of the TDAFW system, and the TDAFW system suction source, the Emergency Condensate Storage Tank (ECST). This issue was entered this into the licensees corrective action program as CR 572803. The licensee failed to maintain an adequate maintenance procedure to set the governor valve on the Unit 1 TDAFW pump to the fully closed position was a performance deficiency (PD). Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage) and is therefore a finding. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and was determined to affect the short term secondary system heat removal safety function within the Mitigating Systems Cornerstone. The finding was determined to represent a loss of system function of the auxiliary feedwater (AFW) system as the incorrectly set governor caused the TDAFW pump to run at higher discharge pressure under low flow conditions, lifting the TDAFW discharge relief valve, which bypassed approximately 200 gpm flow to the ground. With the loss of 200 gpm the ECST could not have met its mission time which represented a loss of system function requiring a detailed risk analysis. A detailed risk analysis was performed by a regional senior reactor analyst (SRA) in accordance with the guidance of NRC IMC 0609, Appendix A, The Significance Determination Process (SDP) for ndings At-Power, dated June 19, 2012, using the NRC North Anna SPAR model. The major analysis assumptions included: the ECST failed for a one year exposure period, no additional failure modes from the incorrectly set TDAFW pump governor valve other than the early depletion of the ECST, and no recovery for the condition other than to align to alternate suction source which remained at nominal failure probability. The dominant sequence was a loss of offsite power with success of reactor protection system, success of the emergency power system and late failure of AFW and late failure of feed and bleed leading to core damage. The risk was mitigated by the availability of other suction sources. The result of the analysis was that the PD represented an increase in core damage frequency of < 1.0 E-6/year, a GREEN finding of very low safety significance. The finding has a cross-cutting aspect in the area of human performance associated with resources attribute because leaders failed to ensure that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety to maintain the ECST inventory during the mission time. |
| 05000338/FIN-2015403-01 | 2015Q1 | Green | NRC identified | Security | ||
| 05000338/FIN-2015001-01 | 2015Q1 | Green | H.5 | Self-revealing | Failure To Follow Procedure For RWST Instruments | A self-revealing NCV of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to follow work management procedures. Specifically, the licensee failed to follow the conduct of maintenance procedure, MM-AA-100, Conduct of Maintenance, Revision 10, where maintenance personnel should use an assortment of techniques and tools to avoid errors during work execution. Attachment 6 step 1b outlines various human error prevention techniques that should have been used during the work execution including self checking and questioning attitude. This issue was entered this into the licensees corrective action program as CR 567185. The licensees failure to follow the conduct of maintenance procedure, MM-AA-100, Conduct of Maintenance, Revision 10, was a performance deficiency. Specifically, on December 10, 2014, maintenance personnel failed to effectively use human error prevention tools when performing the maintenance on the Refueling Water Storage Tank (RWST) level channels which resulted in a loss of the safety function of the Recirculation Spray (RS) system. The performance deficiency was more than minor because it was associated with the configuration control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to ensure that the physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events and is therefore a finding. Specifically, the RS system safety function was inadvertently rendered inoperable. The inspectors performed a Phase 1 analysis using the IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At- Power , Exhibit 3 Barrier Integrity Screening Questions, dated June 19, 2012 and Appendix H, Containment Integrity Significance Determination Process, dated May 6, 2004, and determined the finding required a detailed risk evaluation because it involved the loss of safety function of the RS system. A detailed risk evaluation was performed in accordance with NRC Inspection Manual Chapter (IMC) 0609, Appendix A by a regional senior reactor analyst using the latest NRC North Anna SPAR model and Saphire risk program. The major analysis assumptions included: a thirty-two minute exposure interval, and a non-recoverable loss of both inside recirculation spray pumps and both outside recirculation pumps. The dominant risk sequence was a small break loss of coolant accident initiator, success of the reactor protection system, success of feedwater, success of high pressure injection, success of secondary side cooldown and failure of recirculation spray resulting in loss of core and containment heat removal capability. The risk was mitigated by the short exposure period. The risk evaluation result was an increase in core damage frequency of <1 E-6/year and an increase in large early release fraction of <1 E -7/year, a GREEN finding of very low safety significance. The finding has a cross-cutting aspect in the area of human performance associated with the work management attribute because the organization failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Furthermore, the licensee work process control includes the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities. Specifically, due to poor communication and coordination between the Control Room and the technicians calibrating the RWST level channels, and amongst the team of technicians calibrating the RWST level transmitters, the RS system was inoperable. |
| 05000338/FIN-2014005-01 | 2014Q4 | Green | Licensee-identified | Licensee-Identified Violation | Section 5.5, Programs and Manuals, of North Anna TS stated, in part, that an offsite dose calculation manual shall be established, implemented and maintained. Section 6.2 of VPAP-2103N, Offsite Dose Calculation Manual (North Anna), Revision 23, required that radioactive liquid effluent monitoring instrumentation channels be maintained operable with a trip setpoint which will automatically isolate the discharge line in response to a high radiation condition. Contrary to section 6.2 of VPAP- 2103N, 1-LW-RM-111, the liquid radioactive effluent rad monitor was not maintained operable from May 13, 2014 to September 3, 2014. During the time period that 1-LW-RM-111 was inoperable the licensee was not aware of the situation due to inadequate procedure guidance for daily source checks required to verify operability as defined in 0-LOG-6A. This finding was identified by the licensee and entered i the licensees corrective action program as CR558708, 1-LW-RM-111 not capable of performing design function from 5/13/14 to 9/3/14,and Apparent Cause Evaluation, ACE019800, 1-LW-RM-111 not capable of performing design functions from 5/13/14 to 9/3/14. The inspectors performed a significance determination using NRC Inspection Manual 0609, Appendix D, Public Radiation Safety Significance Determination Process, Section C, dated February 12, 2008. Because the licensee was able to monitor the radioactive effluent release with downstream radiation monitors on the circulating water line which have alarm capability th finding was determined to be of very low safety significance (Green). | |
| 05000338/FIN-2014004-01 | 2014Q3 | Green | H.6 | Self-revealing | Inadequate Procedure for Maintaining MCR/ESGR Air Handler | A self-revealing NCV of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for a failure to prescribe maintenance procedures affecting the quality of fan 1-HV-AC-7 appropriate to the circumstances. Specifically, the licensee failed to incorporate vendor guidance for taking bearing clearance measurements into maintenance procedure 0-MCM-0508-01 Repair Buffalo Forge Centrifugal Fans as required by administrative procedure VPAP-0502. This issue was entered in the licensees corrective action program (CAP) as condition report (CR) 552780. This finding was determined to be more than minor because it affects the reactor safety barrier integrity cornerstone attribute of control room barrier, and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that are required for the habitability of the control room. Specifically, the finding impacted the availability of 1-HV-AC-7, which affects the availability of the MCR/emergency switchgear room (ESGR) air conditioning system (ACS). The finding was determined to be associated with the barrier integrity cornerstone based on the NRC IMC 0609, Significance Determination Process (SDP), dated June 2, 2011, Attachment 4, Initial Characterization of Findings, dated June 19, 2012. The inspectors performed a Phase 1 analysis using the IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At- Power , dated June 19, 2012 and determined that the finding was of very low significance (Green) because the finding did not represent a degradation of the barrier function of the control room against radiation protection, smoke or a toxic atmosphere. The redundant subsystem was able to provide cooling to the MCR/ESGR envelope and it was within the 30-day Technical Specification 3.7.11 LCO. The inspectors determined that this finding had a cross-cutting aspect in the area of human performance, design margins component, because the licensee failed to operate and maintain equipment within design margins where margins are carefully guarded and changed only through a systematic and rigorous process. Specifically, the licensee failed to recognize that the bearing clearance measurement identified in VTM 59-B878-00001 and the SKF Bearing Maintenance Handbook was a critical design parameter. |
| 05000338/FIN-2014004-02 | 2014Q3 | Green | Licensee-identified | Licensee-Identified Violation | 10 CFR Part 50, Appendix B, Criterion III, Design Control required, in part, that design control measures shall provide for verifying or checking the adequacy of design reviews, by the use of alternate or simplified calculation methods, or by the performance of a suitable testing program. Generic Letter (GL) 2008-01 required, in part, licensees to evaluate the potential impact of vortexing on tanks and recirculation sumps. Contrary to the above, since December 2008, the licensee failed to verify the adequacy of design for the casing cooling system to meet Generic Letter (GL) 2008-01 vortex evaluation requirements. Specifically, the licensee identified that the 1990 calculation accounted for vortexing in usable volume, but did not verify that the low-low level setpoint accounted for this required submergence. A detailed risk assessment was performed in accordance with NRC Inspection Manual Chapter 0609 Appendix A using the NRC North Anna standardized plant analysis risk (SPAR) model. The major analysis assumptions included: Non-recoverable common cause failure to run of the outside recirculation spray pumps caused by vortexing of the casing cooling pumps, a one year exposure period, North Anna site specific performance testing restoration values for the Inside Recirculation Spray pumps. Seismic and high wind conditions external event risk was included. The risk evaluation concluded that the violation represented a risk increase in core damage frequency of < 1 E-6 /year, a GREEN finding of very low safety significance. This issue is in the licensees CAP as CR533387, Casing Cooling Tank Low Level Setpoint does not Account for Vortexing. The instruments were recalibrated and tested to the required setpoint. | |
| 05000338/FIN-2014502-01 | 2014Q3 | Green | Licensee-identified | Licensee-Identified Violation | The following LIV of very low safety significance (Green) was identified by the licensee, and is a violation of NRC requirements which met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation (NCV). Title 10 CFR 50.54(q)(2) requires, in part, that a licensee shall follow and maintain the effectiveness of an emergency plan which meets the planning standards of 10 CFR 50.47(b). Title 10 CFR 50.47(b)(4) requires that a standard EAL scheme, the bases of which include facility system and effluent parameters, is in use by nuclear facility licensee, and State and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial offsite response measures. Contrary to the above, from December 30, 2008, to November 6, 2014, the licensee failed to maintain the effectiveness of its emergency plan. Specifically, the standard EAL scheme, Abnormal Rad Release/Rad Effluent-EAL RA2.1 listed an incorrect radiation monitor (Process Vent Normal Range radiation monitor GW-RI-178-1), and should have listed Vent Stack B Normal Range 1-VG-RI-180-1. This violation was determined to be of very low safety significance (Green) because the incorrect EAL only affected Alert declarations. The licensee implemented immediate compensatory actions by issuing a standing order to include the correct radiation monitor, and informed appropriate operators and decision-makers. The issue was placed in their corrective action program as CR531679. | |
| 05000338/FIN-2014003-01 | 2014Q2 | Green | Self-revealing | Failure to Maintain the Diesel Driven Fire Pump | A self-revealing NCV was identified for the licensees failure to meet the requirements of NAPS Renewed Operating License Conditions 2.D, and the approved FPP for NAPS, Units 1 and 2. Specifically, the licensee failed to maintain the diesel driven fire pump water pump with established procedures that incorporated the equipment manufacturers recommended maintenance. Failure to maintain the diesel-driven fire pump water pump with established procedures that incorporated the equipment manufacturers recommended maintenance is a performance deficiency. This finding was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e. fire), and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding impacted the availability of the diesel driven fire pump which adversely impacted the fire protection programs defense-in-depth in the event of a fire. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, which determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, review was required as the finding affected fire water supply. The inspectors evaluated this finding using the guidance in IMC 0609, Appendix F. The pump failed on November 8, 2013, and the last successful test was performed on November 7, 2013. The review determined that the unaffected motor driven fire pump was available to provide at least 50 percent of the required fire water capacity (flow at required pressure) and therefore the finding screened as very low safety significance (Green). The inspectors determined that there was no cross-cutting aspect associated with this finding because it was not reflective of current licensee performance. The violation was entered into the licensees corrective action program (CAP) as CR532383. | |
| 05000338/FIN-2014003-03 | 2014Q2 | Green | Licensee-identified | Licensee-Identified Violation | The failure of the licensee to place the 2A Under Frequency (UF) channel into trip on July 3, 2013, per TS 3.3.1 Condition L constituted a violation of TS. The channel should have been placed in trip within 72 hours. After further testing by the licensee, the 2A UF relay channel was placed in trip on July 10, 2013. A potential transformer blown fuse was replaced and the UV and UF channels were restored to operability on July 22, 2013. The safety function of UF monitoring was maintained by the two remaining operable channels. Using IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the finding was determined to be of very low safety significance (Green) because the finding was not a deficiency affecting the design or qualification of mitigating SSCs, does not represent a loss of system or function, does not represent an actual loss of function of at least a single Train greater than its TS allowed outage time, and does not represent an actual loss of function of one or more non-TS trains of equipment. This issue is in the licensees CAP as CR520296, Unit 2 2A Underfrequency Relay determined Non-Functional. | |
| 05000338/FIN-2014403-01 | 2014Q2 | Green | NRC identified | Security | ||
| 05000339/FIN-2014003-02 | 2014Q2 | Green | H.4 | Self-revealing | Unit 2 Manual Reactor Trip After Loss of Main Feedwater Pump | A self-revealing finding was identified for failure to follow procedure after a feedwater transient that resulted in a Unit 2 manual trip. Specifically, the licensee failed to use diverse or alternate indications, such as motor amps, feedwater pump discharge pressure, feedwater flow, or steam generator levels as required by both OP-AA-100, Conduct of Operations, Revision 25, and OP-AA-1800, Operator Fundamentals, Revision 7, after the loss of A main feedwater pump and the C main feedwater pump motor breaker closed red light failed to light. The inspectors determined that the failure of the licensee to use diverse or alternate indications, as required by plant procedures, when deciding to trip the Unit 2 reactor was a performance deficiency. The performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of human performance and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability. Specifically, the human error associated with not using diverse or alternate indications resulted in an unnecessary plant trip. Using IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the finding was determined to be of very low safety significance (Green) because it was a transient initiator, but did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. In addition, this finding involved the cross cutting area of human performance and the aspect of teamwork, H.4, because the licensee failed to communicate and coordinate actions when verifying the proper operation of the C main feedwater pump after auto start. The licensee is tracking this issue in their corrective action system as Condition Report (CR) 538653. |
| 05000338/FIN-2014002-01 | 2014Q1 | Green | H.12 | Self-revealing | Failure to Mark a Foreign Material Exclusion Closure Device Results in Non-Functionality of the Alternate AC Diesel | A self-revealing finding was identified for the licensees failure to mark a foreign material exclusion (FME) closure device, as required by licensee procedure MA-AA-102, Foreign Material Exclusion, Revision 14. This resulted in the non-functionality of the alternate AC (AAC) diesel. The inspectors reviewed the issue of concern in accordance with IMC 0612, Appendix B, Issue Screening. The inspectors determined that the licensees failure to mark the #4 lifter side cover as an FME closure device as required by licensee procedure MA-AA-102 was a performance deficiency (PD). The PD is more than minor, and therefore a finding, because it adversely affected the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and the related attribute of equipment performance. Specifically, the resultant improper installation of the #4 lifter side cover caused the nonfunctionality of the AAC diesel. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process For Findings At-Power , issued June 19, 2012, and determined that Exhibit 2, Mitigating Systems Screening Question was applicable since the AAC diesel is a mitigating system component. The inspectors determined that a Detailed Risk Evaluation was required because the finding represented an actual loss of function of one or more non-Technical Specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hrs. A detailed risk evaluation of the PD was performed by a regional senior reactor analyst (SRA) using the guidance of NRC Inspection Manual Chapter (IMC) 0609 Appendix A, and the latest NRC North Anna SPAR model. The resultant increase in core damage frequency from the PD was <1E-6/year, a GREEN finding of very low safety significance. In addition, this finding involved the cross-cutting area of Human Performance and the aspect of Avoid Complacency, H.12, because the licensee failed to recognize and plan for the possibility of mistakes caused by not labeling the FME closure device during the AAC diesel maintenance. |
| 05000338/FIN-2014404-02 | 2014Q1 | Green | NRC identified | Security | ||
| 05000338/FIN-2014404-03 | 2014Q1 | Green | Licensee-identified | Licensee-Identified Violation | ||
| 05000338/FIN-2014404-05 | 2014Q1 | Green | Licensee-identified | Licensee-Identified Violation | ||
| 05000338/FIN-2014404-01 | 2014Q1 | Green | NRC identified | Security | ||
| 05000338/FIN-2014404-04 | 2014Q1 | Green | Licensee-identified | Licensee-Identified Violation | ||
| 05000338/FIN-2013004-02 | 2013Q4 | Green | H.13 | Self-revealing | Failure to Establish and Implement Adequate Preventative Maintenance Causes a Reactor Trip | A Green self-revealing finding was identified for failure to establish and implement adequate preventative maintenance for the mechanism operated cell (MOC) switches. Specifically the licensee failed to recognize and recommend proper maintenance for these components on the C main feedwater pump motor circuit breakers. The inspectors determined that the licensees failure to establish and implement adequate preventive maintenance for MOC switches in accordance with industry guidance through EPRI, the vendor, ABB, and operating experience was a performance deficiency. The performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of equipment performance and adversely affected the associated cornerstone objective in that loss of conductivity across contacts 25 and 26 in the upper MOC switch for circuit breaker 2-EP-BKR-25C5 caused the spurious closure of the C main feed pump discharge valve (2-FW-MOV-250C) and indirectly resulted in a manual reactor trip. Using Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the finding was determined to be of very low safety significance (Green) because it was a transient initiator, but did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. In addition, this finding involved the cross cutting area of human performance, the component of decision making, and the aspect of systematic process for decision, H.1(a), because the licensee did not make risk-significant decisions using a systematic process for preventative maintenance activities when they failed to recognize and recommend proper maintenance for the MOC switches. |
| 05000338/FIN-2013004-01 | 2013Q4 | Green | Self-revealing | Failure to Provide Vendor Oversight Results in a Manual Reactor Trip | A Green self revealing finding was identified for the failure to properly provide oversight over supplemental (vendor) personnel during the replacement of the Unit 2 turbine and exciter rotors during the spring of 2010 in accordance with Dominion procedure MA-AA-1001, Supplemental Personnel, Revision 9. The failure to properly provide oversight over supplemental (vendor) personnel in accordance with Dominion procedure MA-AA-1001, Supplemental Personnel, section 3.8.1, during the spring 2010 replacement of the Unit 2 turbine and exciter rotors was a performance deficiency. The performance deficiency was more than minor because it adversely affected the Initiating Events cornerstone objective of reliability because the failure to properly conduct procedure MA-AA-1001 directly resulted in the upset of plant stability by tripping the unit and the challenge of critical plant safety functions. Using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, issued June 19, 2012, the finding screens to green because although a reactor trip occurred, the loss of mitigating equipment for transitioning the plant to a safe shutdown condition did not occur. There is no cross cutting aspect for this finding because the initial cause of the finding occurred more than 3 years ago following turbine and exciter rotor replacement. | |
| 05000338/FIN-2013005-01 | 2013Q4 | Green | H.7 | Self-revealing | Failure to Follow Work Instructions for the Replacement of Protective Relays Causes a Unit 1 Reactor Trip Due to Loss of Station Service Bus Transformer After Start of 1C Condensate Pump | A Green, self-revealing finding was identified for failure to follow procedure for the replacement of protective relays that resulted in a Unit 1 trip. Specifically, the instructions in work order (WO) 59102618778 stated to Have Control Ops install shorting screws for CT circuit, and Have Control Ops remove shorting screws for CT circuit. Maintenance personnel failed to remove the current transformer terminal block shorting screws installed inside the 1C switchgear breaker 15C2 cubicle and caused the turbine to trip and the reactor to trip from the loss of the 1C station service transformer after the start of the C condensate pump. This was entered into the licensees CAP as CR528984. The inspectors determined that the licensees failure to follow work instructions in WO59102618778 which stated to Have Control Ops install shorting screws for CT circuit, and Have Control Ops remove shorting screws for CT circuit for the replacement of protective relays was a performance deficiency. The performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of equipment performance and adversely affected the associated cornerstone objective in that maintenance personnel left the current transformer terminal block shorting screws installed inside the 1C switchgear breaker cubicle which caused the turbine trip and subsequent reactor trip from the loss of the 1C station service transformer after the start of the C condensate pump. Using Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the finding was determined to be of very low safety significance (Green) because it was a transient initiator, but did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. In addition, this finding involved the cross cutting area of human performance, the component of resources, and the aspect of complete, accurate, and an up-to-date work instructions, H.2(c), because the work order job steps did not contain adequate means for documenting the installation and removal of shorting screws, which resulted in a loss of configuration control for the 1C switchgear 15C2 breaker cubicle. |
| 05000338/FIN-2013005-02 | 2013Q4 | NRC identified | Fuse Failures in 1H Emergency Diesel Generator Governor Circuit | An unresolved issue (URI) was identified by the inspectors relating to an issue involving the licensees failure to establish and implement adequate PM for the 1H EDG control system fuse holders that were susceptible to relaxation of the spring clips. At 0005 on October 6, 2013, during the performance of 1-PT-83.7H, 1H EDG 24-Hour Run, the 1H EDG unexpectedly unloaded without warning or operator action and was tripped from the control room by the operators after 15 hours of operation. The 1H EDG is the Unit 1 Train A EDG that supplies emergency 4160V AC power to the Vital Electrical Distribution System Bus 1H. The 1J and 1H EDGs are the Unit 1 dedicated redundant power supplies of emergency 4160V AC power to the Vital Electrical Distribution System. At the time of the event 1J EDG was operable. The licensee entered this event in their corrective action program as CR528386 and initiated an apparent cause evaluation ACE19593, 1H-EDG Loss of Load During 24-hr Testing. The licensee stated in their ACE of the 1H EDG that the fatigue of the fuse clip most likely occurred from repeated insertion and removal of the fuses during the recent troubleshooting, maintenance, and the recent outage upgrade of the governor control system. The inspectors require additional information from the licensee to determine if there is a performance deficiency which is more than minor. This issue is identified as URI 05000338/2013005-02, Fuse Failures in 1H Emergency Diesel Generator Governor Circuit. | ||
| 05000338/FIN-2013003-02 | 2013Q2 | Green | Licensee-identified | 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 or procedures appropriate to the circumstances. Contrary to this, following the January 2, 2013 leak on the 2H EDG, the licensee identified that in May 2010 licensee personnel failed to prescribe the installation of rubber expansion joints on the 2H EDG with procedures or instructions appropriate to the circumstances. Specifically DC-NA-09-00170, EDG Lube Oil S-Line Flexible Connection did not contain post design change testing instructions that verified that the design change did not create an unintended deficiency as required by CM-AA-DDC-301, Post Design Change Testing , Revision 1. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time or two separate safety systems out-of-service for greater than its technical specification allowed outage time. The inspectors determined that the licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR501347. | |
| 05000338/FIN-2013003-01 | 2013Q2 | Green | Licensee-identified | Licensee-Identified Violation | Technical Specification 5.4.1.a states, in part, that written procedures shall be implemented covering the applicable procedures recommended in RG 1.33, Revision 2, Appendix A, February 1978, of which Section 9 specifies procedures for performing maintenance. Contrary to this, on March 21, 2013, the licensee identified that during the week of March 18, 2013, maintenance personnel tightened the locking collar set screws on the Unit 2 A charging pump to an incorrect torque value of 10.5 ft-lbs, as specified in station procedure 0-MCM-0103-01, Repair of the Charging and High Head Safety Injection Pump, Step 6.32.6, instead of the manufacturer recommended value of 35 ft-lbs. Specifically, the Unit 2 A charging pump was degraded because the mechanical shaft sleeve overheated during pump operation due to insufficient tightening of the locking collar set screws. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time or two separate safety systems out-of-service for greater than its technical specification allowed outage time. The inspectors determined that the licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR508838. | |
| 05000338/FIN-2013002-01 | 2013Q1 | Green | NRC identified | Failure to Ensure Opposite Units Service Water Pumps Were Free of Fire Damage for a Postulated Fire in Either Units ESWGR | An NRC-identified non-cited violation was identified for the licensees failure to meet the requirements of North Anna Power Station (NAPS) Renewed Operating License Conditions 2.D, and the approved Fire Protection Program for Units 1 and 2. Specifically, the licensee failed to ensure that fire damage to cables associated with the opposite units service water (SW) pumps, located in each units emergency switchgear (ESWGR) room, would not prevent operation of the unaffected units SW pumps as described in Section 4.4.3.5 of the NAPS Appendix R Report. Postulated fire scenarios were identified in which the SW pumps for both units could be compromised due to a single fire in either units ESWGR room. The licensee had previously entered this issue in the NAPS corrective action program as condition report 500152 to evaluate this SW pump control circuit vulnerability and had implemented hourly roving fire watches in each units ESWGR room. Failure to perform an adequate safe shutdown (SSD) analysis as required by the NAPS FPP is a performance deficiency. This finding was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e. fire), and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding had the potential to affect the ability to achieve post-fire SSD in the event of a fire in either units ESWGR. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, which determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, dated February 28, 2005, review was required as the finding affected fire protection safe shutdown. The inspectors evaluated this finding using the guidance in IMC 0609, Appendix F. The inspectors performed Phase 1 and Phase 2 SDP screening assessments using IMC 0609, Appendix F, Attachments 1 and 2, and were not able to screen out this issue in the SDP Phase 1 or Phase 2. A senior reactor analyst from the Region II office performed a Phase 3 SDP analysis to assess the significance of this finding. The analyst determined that this finding was of very low safety significance (i.e., Green) because the risk was mitigated by the availability of at least one SW pump and the fire growth scenarios were mitigated by the gaseous suppression system. The inspectors determined that there was no cross-cutting aspect associated with this finding because it was not reflective of current licensee performance. | |
| 05000338/FIN-2013007-01 | 2013Q1 | Green | Self-revealing | Failure to Implement Vendor Recommendations Causes an Automatic Reactor Trip | A self-revealing finding was identified for failure to establish and implement appropriate periodic preventive maintenance for replacement frequency of the C4 capacitor on the Speed Error Amplifier card B (1A08D) in accordance with VPAP-803, Preventive Maintenance Program. Consequently, the C4 capacitor failed due to age related degradation and caused an automatic reactor trip from 100 percent reactor power. The licensees failure to establish and implement appropriate periodic preventive maintenance for replacement frequency of the C4 was a performance deficiency. The finding was more than minor because it was associated with the Initiating Events cornerstone attribute of equipment performance and adversely affected the associated cornerstone in that a reactor trip occurred. The finding was determined to be of very low safety significance (Green) because it was a transient initiator, but did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. The finding did not have a crosscutting aspect because the performance deficiency was not indicative of current plant performance. |