Semantic search
Jump to navigation
Jump to search
| Q | Significance | CCA | Identified by | Title | Description | |
|---|---|---|---|---|---|---|
| 05000390/FIN-2001002-02 | 2001Q2 | Severity level II | NRC identified | Employee Protected Activity | On February 7, 2000, a Severity Level II violation with a proposed civil penalty was issued to the licensee. The violation related to corporate activities and involved employment discrimination contrary to the requirements of 10 CFR 50.7, "Employee Protection," in that the licensee did not select a former employee to a competitive position in the corporate chemistry organization in 1996, due, at least in part, to his engagement in protected activities. On January 22, 2001, the licensee denied the violation and on May 4, an Order was issued sustaining the violation and imposing the civil penalty. On June 1, TVA requested an enforcement hearing on the Order. | |
| 05000390/FIN-2002006-02 | 2002Q1 | Severity level IV | NRC identified | Exposure of a minor in third quarter of 1981 in excess of the requirements of 10 CFR 20.104 | 10 CFR 20.401 and subsequently 10 CFR 20.2106 requires that the licensee maintain records of doses received by all individuals for whom monitoring was required. 10 CFR 50.9 requires, in part, that information required by the Commissions regulations to be maintained shall be complete and accurate in all material respects. Contrary to these requirements, the licensee failed to maintain accurate records of personnel exposures during the period 1970 to 1999. This violation was not assessed in accordance with the significance determination process because it was identified and corrected prior to implementation of the Reactor Oversight Process and involved a violation of 10 CFR 50.9. Therefore, in accordance with Section VI of the Enforcement Policy, this licensee identified and corrected Severity IV violation is being characterized as a non-cited violation (NCV) and is identified as NCV 50-259/01-08-02, 50-260/01-08-02, 50-296/01-08-02, 50-327/02- 06-02, 50-328/02-06-02, 50-390/02-05-02 and 50-391/02-05-02) 1, Failure to maintain complete and accurate personnel dose records as required by 10 CFR 20.401, 10 CFR 20.2106, and 10 CFR 50.9 . This issue is in the licensees corrective action program as Problem Evaluation Report (PER) CHSCA940002 Personnel Exposure Records-Reconciliation Project. | |
| 05000390/FIN-2003002-02 | 2003Q2 | Severity level IV | NRC identified | Noncompliance of the Unit 2 Layup Process to10 CFR 50, Appendix B | The inspectors identified that the applicant had initiated an unapproved reduction in equipment preservation to the Unit 2 lay-up process. The applicant had elected to cease performing preventive maintenance on many components An inspector-identified, non-cited violation of 10 CFR 50, Appendix B, Criteria XIII, Identification and Control of Materials, Parts, and Components, was identified. This finding satisfied a traditional enforcement criterion of failure to receive NRC approval for a change in licensee activity In accordance with the NRC Enforcement Policy, the finding was characterized as a Severity Level IV NCV involving a failure to receive prior NRC approval for a change in licensee activity (Section 4OA5). | |
| 05000390/FIN-2004005-01 | 2004Q4 | Green | NRC identified | Failure to Provide Complete and Accurate Information to the NRC Which Impacted a Licensing Decision. | The inspectors identified a non-cited Severity Level IV violation (NCV) of 10 CFR 50.9 for failure to provide complete and accurate information for one licensed operator on his initial license application. The applicant did not meet the American Nuclear Standards Institute /American Nuclear Society (ANSI/ANS) 3.4, 1983, standard for visual acuity without corrective lenses and had a pre-existing medical condition, both of which required a license restriction. The licensee submitted his NRC Form 396, Certification of Medical Examination by Facility Licensee, along with supplemental medical information, without recommending these restrictions. The NRC imposed a no-solo restriction on the operator's license after reviewing the supplemental information. The failure to certify the need for corrective lenses resulted in an incorrect licensing action by the NRC because a license was issued without a restriction to wear corrective lenses. Because this issue affected the NRC's ability to perform its regulatory function, it was evaluated using the traditional enforcement process. This finding is of very low safety significance because there was no evidence that the operator endangered plant operations as a result of impaired visual acuity while performing licensed duties since the original issuance of his license. However, the regulatory significance was important because the incorrect information was provided under sworn statement to the NRC and impacted a licensing decision for the individual. The facility licensee took prompt corrective action and submitted NRC Form 396 requesting to have the operator's license amended with the appropriate restriction. This issue is documented in the facility licensee's corrective action program as Problem Evaluation Report (PER) 72386. | |
| 05000390/FIN-2006005-01 | 2006Q4 | NRC identified | Potential failure to properly reactivate RO/SRO licenses | During the biennial requalification inspection, the inspectors identified that RO/SRO licenses were reactivated without following the guidance in Procedure OPDP-1, which required a plant tour with a licensed operator that included those areas covered by shift rounds. OPDP-1 implemented the regulatory requirements of 10 CFR 55.53(f) which specifies that in order to activate an operator license, a complete tour of the plant shall be completed with a licensed operator. The inspectors compared the information contained in four reactivation records with vital area computer access records to verify the plant tours were performed as indicated. The inspectors identified that two operators had potentially not satisfied the requirements for conducting a complete plant tour as part of reactivating their RO or SRO license respectively. The licensee was not able to provide documentation, in the form of security card reader records, that would confirm that an RO performed his tour in the presence of an active RO or SRO licensed individual. Also, records supplied by the licensee showed that an SRO who was reactivating his license performed his tour with an SRO whose license was not currently active. 10 CFR 55.53(f), Conditions of a License, states, in part, that the licensee has completed a minimum of 40 hours of shift functions under the direction of an operator or senior operator as appropriate and in the position to which the individual will be assigned. The 40 hours must have included a complete tour of the plant and all required shift turnover procedures. To ensure 10 CFR 55.53 (f) requirements are satisfied, the licensee has established Procedure OPDP-1, Conduct of Operations Attachment P, which states, The licensee has completed a minimum of 40 hours of shift functions under the directions of an active RO or SRO and in the position to which the operator is to be assigned. The 40 hours must include a complete plant tour (with an active licensed operator) of the plant and a review of all required shift turnover procedures. This tour shall be in those areas covered by shift rounds. TS 5.7.1.1(a) requires written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, Administrative Procedures. OPDP-1 is a written procedure that is required by TS 5.7.1.1(a). On August 18, 2006, the inspectors identified that the licensee potentially failed to properly reactivate two licensed operators on May 20, 2005, and January 21, 2006, in accordance with procedure OPDP-1. The licensee entered this issue into their CAP as PER 108957. This item is identified as URI 05000390/2006005-01, Potential failure to properly reactivate RO/SRO licenses, and is unresolved pending additional NRC review of the circumstances and information regarding the reactivation of these two licensed operators. | ||
| 05000390/FIN-2006007-01 | 2005Q1 | White | NRC identified | Failure to Implement and Maintain Shutdown Procedures Which Resulted in Pressurizer PORV Actuations. | The inspectors identified a finding associated with TS 5.7.1.1 requirements for procedure adherence which resulted in pressurizer power-operated relief valve (PORV) actuations. The finding is unresolved pending significance determination assessment. The inspectors determined that procedural noncompliances had a credible impact on safety involving the challenge of reactor coolant system (RCS) integrity by PORV actuations and the challenge of RCS inventory through the loss of inventory via the open PORVs. The finding was more than minor because it impacted the Barrier Integrity Cornerstone objective to provide reasonable assurance that the RCS physical design barrier protects the public from radionuclide releases caused by accidents or events and the associated cornerstone attributes of human performance and procedure quality. The inspectors reviewed MC 0609, Appendix G, and determined that the finding required quantitative assessment consisting of a Phase 3 analysis because it affected the cold over-pressure mitigation or low temperature over-pressure system required by TS. The cause of the finding impacts the cross-cutting area of human performance. (Section 1R20.2) | |
| 05000390/FIN-2007007-01 | 2007Q2 | NRC identified | CO2 System in FA 48 Appears to Deviate from Design Criterion in Sser | Alternate shutdown capability was provided to cope with a fire in FA 48, the auxiliary instrumentation room containing the RPS cabinets. Alternate shutdown was the chosen coping strategy for this room because it contained all channels of normally used instrumentation circuits and associated panels in close proximity, making it difficult t protect any one channel. A CO2 suppression system was installed in this room to meet the requirements of Appendix R, Section III.G.3. Design basis documents applicable t the design of the CO2 system were: National Fire Protection Association Standard on Carbon Dioxide Extinguishing Systems, NFPA No.12 - 1973, NRC Supplemental Safety Evaluation Report (SSER) No. 18 (NUREG 0847), and Watts Bar Fire Protection Report (FPR). Review of these documents by the team identified an issue. The SSER states that the CO2 system must achieve a concentration of at least 50 percent within seven minutes of initiation and hold that concentration for 15 minutes. This statement may be construed as meaning the concentration values must be achieved at any point in the room where combustibles capable of deep seated fires are located. The basis for these values in the SSER is testing performed by Sandia National Laboratory on deep seated fires and CO2 systems as described in NRC Information Notice 92-28, Inadequate Fire Suppression System Testing, issued April 8, 1992. The FPR states that the system is capable of achieving 50 percent concentration within seven minutes and maintaining at least a 45 percent concentration for at least 15 minutes. NFPA No.12 - 1973 (the code of record) specifies 50 percent concentration for deep seated fires, but does not specify a definite hold time. The issue is: Given the difference between the SSER and the FPR with regard to the required concentration at the 15 minute point, does the CO2 system meet the design basis? The team reviewed records of a discharge test conducted at the time of initial system installation. The team found that it was a valid test, and that it confirmed the values stated in the FPR with regard to CO2 concentrations. Records showed that a 45 percent concentration was held for 15 minutes measured at 75 percent of room height. Fifty percent concentration for 15 minutes was achieved in the lower half of the room. FA 48 contains a mixture of both thermoset and thermoplastic-type cables. Fire in fire resistant thermoset-type cables could be a deep seated fire. Fire in thermoplastic-type cables would be a surface fire. For the cable trays located in the upper 25 percent of the room, the team did not determine what percentage of these cables were of the thermoset-type. The licensee considered the CO2 system to be functional. Testing demonstrated that 50 percent CO2 concentration for 15 minutes would be achieved in the lower half of the room where the ignition sources in the form of low-voltage, low-power, instrumentation cabinets were located. The possibility of a fire starting in the cabinets spreading to the 8 upper portions of the room along the cables is unlikely because the great majority of the cables are routed in conduits or enclosed raceway as they exit from the tops of the cabinets (i.e. for the first five to seven feet). The only ignition sources in the upper 25 percent of the room would be these thermoplastic cables located in the cable trays. Because the coping strategy for a fire in this fire area is alternative shutdown, none of the cables in this room are used for SSD. Operation of transfer/isolation switches would be necessary to allow the alternative shutdown system to function properly. The licensee initiated Problem Evaluation Report (PER) 125632 to address the issues described in this section. The team concluded that if the fire hazards and the suppression system in FA 48 were properly analyzed, there would be reasonable expectation that such analysis would show the suppression system to be adequate to extinguish any credible fire. In consideration of the above facts and circumstances, an unresolved item (URI) has been established to allow the licensee reasonable time to generate a documented analysis to show that the CO2 system meets the intent of the design basis as stated in the SSER. For a plant licensed to operate after 1979, such an analysis would not have to be submitted to the NRC as a request for approval of modification of License Condition 2F if it does not adversely affect SSD. This issue is identified as URI 05000390/2007007-01, CO2 System in FA 48 Appears to Deviate From Design Criterion in SSER | ||
| 05000390/FIN-2007007-04 | 2007Q2 | NRC identified | Fire Protection Program DID Not Demonstrate EIGHT-HOUR Emergency Light Unit Battery Capacity | This issue is a performance deficiency because the licensee did not follow its approved FPP for replacement of batteries in the emergency lighting units to demonstrate conformance with the eight-hour capacity requirement on a continuing basis. The finding is more than minor because it is associated with the reactor safety, mitigating systems, cornerstone attribute of protection against external factors (i.e. fire) and it affects the objective of ensuring reliability and capability of systems that respond to initiating events. Because the finding adversely affected to some degree the ability to carry out local operator actions required to achieve and maintain a SSD condition following a severe fire, the Phase 1 Significance Determination Process (SDP) for fire indicates that a Phase 2 analysis should be performed. To what degree the finding affected the ability to carry out operator actions depended on how long the ELUs would have actually lasted. Preliminary evaluations by the team indicated that, if the ELUs would have provided adequate illumination for 60 to 90 minutes, the finding would be of relatively low significance. Because there was insufficient objective evidence at the time of this report to determine whether the ELUs would have provided adequate illumination for 60 to 90 minutes, the significance of the finding was considered indeterminate until that question can be resolved. The ELUs which were replaced as a result of this finding have been retained by the licensee. Testing of these ELUs could provide objective evidence important to resolving the issue. Since further information concerning the capacity of the ELU batteries was needed to begin the SDP, an unresolved item was established. It was identified as URI 05000390/2007007-04, Fire Protection Program did not Demonstrate Eight-Hour Emergency Light Unit Battery Capacity. | ||
| 05000390/FIN-2008002-01 | 2008Q1 | Green | Self-revealing | Failure to Properly Prepare a Radioactive Material Package for Shipment | A self-revealing NCV of 10 CFR 71.5 was identified for failure to properly package radiological material such that, under conditions normally incident to transportation, the radiation levels at the external surface of the package would not exceed applicable Department of Transportation (DOT) limits. When the shipment of equipment arrived at a processing facility on March 3, 2008, the contact radiation dose rate measurement in a small area on the bottom of the external surface of one of the packages was 340 mrem/hr, which was in excess of the 200 mrem/hr limit. Subsequent measurements by the licensee determined the dose rate to be 400 mrem/hr. This finding was entered into the licensees corrective action program as Problem Evaluation Report (PER) 139447. This finding is more than minor because it is associated with the plant facilities/ equipment and instrument attribute of the Public Radiation Safety Cornerstone and adversely affected the cornerstone objective, in that the improper transportation packaging resulted in a shipping container with external dose rates exceeding regulatory requirements. Using the Public Radiation Significance Determination Process, the finding was determined to be of very low safety significance because the area on the package with the elevated radiation level was inaccessible to the public and the radiation level did not exceed two times the DOT limit. This finding was reviewed for cross-cutting aspects and none were identified. (Section 2PS2 | |
| 05000390/FIN-2008002-02 | 2008Q1 | Green | H.8 | NRC identified | Failure to Follow Procedure Resulted in Inadequate Control of Materials Brought Into Containment | The inspectors identified a NCV of Technical Specification (T.S.) 5.7.1 for failure to properly implement procedural requirements and engineering controls for materials brought into containment while the plant was at power. The procedural violation resulted in temporary equipment/material left in containment with incorrect/incomplete documentation. The licensee entered these issues into the corrective action program (CAP) and either removed or properly evaluated the materials left in containment. This finding is more than minor because it was associated with the Mitigating Systems Cornerstone attribute of equipment performance, specifically reliability, and adversely affected the cornerstone objective. The finding is of very low safety significance because no equipment was rendered inoperable. The finding directly involved the cross-cutting area of human performance under the procedural compliance aspect of the work practices component, in that, the procedural requirements of the licensees procedure for containment access were not met and equipment/material left in containment was not properly analyzed and documented. (H.4 (b)) (Section 4OA2 |
| 05000390/FIN-2008002-03 | 2008Q1 | Green | NRC identified | Failure to Ensure Adequate Design and Testing of RHR Flow Limiters | The inspectors identified an unresolved item (URI) for failure to properly control the design of devices affecting the function of the RHR Flow Control Valves. This URI will remain unresolved pending additional inspection to determined if a violation of regulatory requirements occurred. Description: On March 14, 2008, inspectors observed the licensee preparing the RHR System for mid-loop operation. Procedure GO-10, Reactor Coolant System Drain and Fill Operations, Appendix Q requires flow limiting devices to be installed on both the RHR Heat Exchanger Bypass Valve, 1-FCV-32 and RHR Heat Exchanger Outlet Valve, 1-FCV-16 for A train. The purpose of these devices is to limit RHR flow in the event of a loss of nonsafety related instrument air, thus causing pump cavitation and potential air binding of the RHR pumps at mid-loop. Communications between field personnel installing the devices and the Control Room Operators indicated that they were experiencing difficulty configuring the devices. Later reports indicated that two devices had been installed on the bypass valve and one was removed. Based on the wording in Appendix Q which says in step one to FABRICATE blocking devices suitable for application to the operators of the applicable valves on the operating train (similar to Figure 1) and the apparent difficulty with the installation, the inspectors asked if the valves were to be opened such as to engage the blocking devices to ensure actual flow was not higher than expected. Control room personnel indicated that there was no plan to do this. Inspectors questioned the basis of not verifying the functionality of the devices, and the control room personnel agreed to raise flow on each valve until the flow limiter blocked further increase. The bypass valve was tested first by raising flow to the limiter, then reducing flow below the initial flow and that back to the desired flow. The bypass valve functioned as expected. A similar test on the outlet valve proceeded smoothly until the Operator attempted to raise the flow back to the original flow. The Operator was unable to raise flow back to the original flowrate. The devices were removed, but later reinstalled and mid-loop operations continued. Inspectors went into the 1A RHR Heat Exchanger Room to observe these devices as they were being reinstalled. The devices were similar to the drawing in Appendix Q in terms of function, but not much so in terms of fit and form. Appendix Q shows a 2 inch outside diameter cylinder with a 7/8 inch, axial hole and three holes on each side drilled into the device for six bolts, with length to be determined in the field (i.e. sufficiently long to limit to the desired flow). The actual devices observed, appeared to be a length of pipe split axially, and held on the actuator stem with a single center mounted hose clamp. The operator had some difficulty installing them due to rubber gloves and due to the fact that the wall of the pipe was thin and difficult to hold aligned while the hose clamp was tightened. Analysis: The finding 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 that modifications of systems did not increase the likelihood of a loss of decay heat removal. Enforcement: An unresolved item was identified pending additional inspection to determine if a violation of regulatory requirements occurred. This unresolved item is identified as URI 50-390/2008002-03, Failure to Ensure Adequate Design and Testing of RHR Flow Limiters | |
| 05000390/FIN-2008003-01 | 2008Q2 | Green | P.3 | NRC identified | Plant Startup with Inoperable AFW Automatic Start on Trip of All MFW Pumps | A Green, NRC-identified non-cited violation of Technical Specification 3.0.4.a was identified for entering Modes 2 and 1 without an operable channel of auxiliary feedwater automatic start on a trip of all main feedwater pumps as required by TS 3.3.2. The licensee defeated this channel by introducing a signal that artificially indicated that a main feedwater pump was operating. This practice existed since initial plant startup. The licensee entered this issue into their corrective action program as Problem Evaluation Report 147351. The finding is more than minor because it is associated with the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability of systems that respond to initiating events. Using IMC 0609, Appendix 0609.04, the finding was determined to be of very low safety significance because the finding did not represent an actual loss of safety function of a single train for greater than its TS allowed outage time since other initiation signals were available to automatically start the auxiliary feedwater pumps if needed. The cause of the finding was directly related to the Implementation of Corrective Actions aspect in the Problem Identification and Resolution cross-cutting area, in that, the licensee failed to take appropriate corrective action in a timely manner to address the non-cited violation issued in NRC Inspection Report 05000390/2006004 associated with making plant mode changes with the auxiliary feedwater automatic start function trip of all main feedwater pumps inoperable (P.1(d)). (Section 4OA2.2 |
| 05000390/FIN-2008003-02 | 2008Q2 | Green | H.7 | Self-revealing | Failure to Comply with Technical Specification 3.3.2 to Have Two Trains of Automatic Actuation Logic and Actuation Relays for Safety Injection and Feedwater Isolation Operable | A Green, self-revealing non-cited violation of Technical Specification 3.3.2 was identified for failure to have two trains of safety injection (SI) automatic actuation logic and two trains of feedwater isolation actuation logic operable while in Mode 3. Upon the removal of temporary jumpers, the relay which blocks the actuation circuitry from performing their function was not reset. This condition existed until approximately 12 hours later when the licensee reset the relay by closing the reactor trip breakers. The licensee entered this event into their corrective action program as Problem Evaluation Report 140641. This finding is more than minor because it affected the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events and adversely affected the cornerstones equipment performance attribute for availability and reliability. A Phase 2 evaluation in accordance with IMC 609, Significance Determination Process, determined the finding to be of very low safety significance (Green) because of the low decay heat at the end of a refueling outage; the time for operators to take recovery actions; and due to the plant conditions, only the containment high pressure SI actuation portion of the automatic SI actuation logic was affected. The cause of the finding was directly related to the documentation, procedures and component labeling cross-cutting aspect in the resources component of the Human Performance cross-cutting area, in that, the instructions used by personnel to remove the temporary jumpers failed to provide necessary steps to ensure the actuation logics were returned to an operable status (H.2(c)). (Section 4OA3 |
| 05000390/FIN-2008003-03 | 2008Q2 | Green | Licensee-identified | Licensee-Identified Violation | The following violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements that meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV. TS 3.3.2 requires that the ESFAS instrumentation for each function in Table 3.3.2-1 shall be operable. Table 3.3.2-1 function 1b, required two trains of SI automatic actuation logic and actuation relays be operable in Modes 3 and 4. Table 3.3.2-1 Function 5a, required two trains of turbine trip and feedwater isolation automatic actuation logic and actuation relays be operable in Mode 3. Contrary to this, on March 20 and 21, 2008, two trains of SI automatic actuation logic were not operable, in that, both trains were blocked. Also on March 21, two trains of SI and feedwater isolation automatic actuation logic were not operable, in that, both trains were blocked. This finding is more than minor because it affected the Mitigating Systems Cornerstone objective and adversely affected the cornerstones equipment performance attribute for availability and reliability. A phase 2 SDP evaluation determined that the finding was of very low safety significance | |
| 05000390/FIN-2008004-01 | 2008Q3 | Green | P.2 P.1(a) | NRC identified | Installation of Different RHR flow Limiters Than Prescribed by Procedure | A Green, NRC-identified, non-cited violation of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for installing flow limiting devices, on A-train residual heat removal (RHR) system valves, which were not equivalent to those described in operating procedures. The devices were installed at reduced reactor coolant system (RCS) inventory to prevent pump cavitation in the event of a loss of control air during upcoming midloop operation. The nonconforming device caused the RHR heat exchanger outlet valve not to fully return to its desired throttled position after verification that the flow limiting devices would limit flow within specified values. The licensee entered this issue into their corrective action program (CAP) as problem evaluation report (PER) 140284. The finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown. The finding was evaluated by a Phase 2 analysis in accordance with the Significance Determination Process as specified by Manual Chapter 0609, Appendix G, Checklist 3 (one train of decay heat removal was degraded). The Phase 2 analysis characterized the finding as of very low safety significance (Green) because of the slow RCS heatup rate due to the low decay heat after being shutdown for 32 days and the ease of recovery from the condition. The cause of the finding was directly related to the corrective action program issue identification aspect of the cross-cutting area of Problem Identification and Resolution, in that, the licensee failed to identify the discrepancy in form, fit, and manner in which the function was accomplished between the flow limiting devices that were specified in licensee procedures and those that were actually installed (P.1(a)). (Section 4OA3.2 |
| 05000390/FIN-2008005-01 | 2008Q4 | Green | Self-revealing | Failure to Translate ERCW Pump Coupling Material Change into Procedures | A Green self-revealing non-cited violation of 10 CFR 50 Appendix B, Criterion III, Design Control, was identified for the failure to adequately translate material specifications into procedures. As a result, the B-A essential raw cooling water (ERCW) pump coupling failed due to an improper material being used. The licensee entered this issue into their corrective action program as Problem Evaluation Report 148716. This finding is more than minor because it affects the plant modifications area of the design control attribute of the Mitigating Systems Cornerstone objective of reliability and availability, and if left uncorrected, it would result failure of other ERCW pumps. This finding was evaluated using the Significance Determination Phase 1 screening criteria and was determined to be of very low safety significance because the finding did not represent an actual loss of safety function of a single train of equipment for greater that its Technical Specification allowed outage time. (Section 1R18.1 | |
| 05000390/FIN-2008005-02 | 2008Q4 | Green | P.2 | NRC identified | Failure to Incorporate Design Parameters into Plant Setpoint Document for the Containment Particulate Radiation Monitor | The NRC identified a Green, non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for failure to translate revised design parameters into the setpoint and scaling document for the lower containment particulate radiation monitor. As a result, the radiation monitor was inoperable, due to incorrect alarm setpoints, for longer than the Technical Specification allowed out of service time. The licensee corrected the radiation monitor alarm setpoint and initiated entered the issue into their corrective action program as Problem Evaluation Report 154635. The inspectors concluded that the finding was more than minor because the radiation monitor inoperability resulted in potential impact on reactor safety and adversely affected the availability and reliability of the equipment performance attribute of the Initiating Events Cornerstone. This finding was evaluated using the Significance Determination Process Phase 1 screening criteria and was determined to be of very low safety significance because other methods of reactor coolant system leak detection were available. The finding directly involved the cross-cutting area of Problem Identification and Resolution under the thorough evaluation of identified problems aspect of the corrective action program component, in that, the licensee failed to properly evaluate the radiation monitors as-found alarm setpoint, which was substantially different than the specified setpoint, prior to resetting the alarm setpoint to the larger value (P.1.c). (Section 4OA2.4 |
| 05000390/FIN-2008005-03 | 2008Q4 | Green | H.11 H.12 | Self-revealing | Performing Non-Authorized Activities on Exciter Field Breaker Results in Reactor Trip | A Green self-revealing finding was identified for the failure to obtain authorization prior to opening the main generator exciter field breaker compartment and operating the de-latching bar. The licensees procedures for controlling sensitive plant equipment specified that personnel obtain the Unit Supervisors authorization prior to beginning work on sensitive equipment. Operating the de-latching bar resulted in the exciter field breaker opening which resulted in the turbine generator and the reactor tripping. The licensee entered this issue into their corrective action program as Problem Evaluation Report 152955. The finding was more than minor because it was associated with the Human Performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during at-power operations. This finding was evaluated using the Significance Determination Process Phase 1 screening criteria and was determined to be of very low safety significance because the finding did not contribute to both a reactor trip and the likelihood of mitigation equipment or functions not being available. The cause of the finding was directly related to the human performance and error prevention aspect of the cross-cutting area of Human Performance, in that, personnel failed to use the self-checking technique to stop and consider their actions for two minutes prior to proceeding with an activity (H.4.a). (Section 4OA3.3 |
| 05000390/FIN-2008005-04 | 2008Q4 | Green | NRC identified | Carbon Dioxide System in Fire Area 48 Failed to Meet Design Criterion | The NRC identified a Green, non-cited violation of Unit 1 Operating License Condition 2.F for not having a carbon dioxide (CO2) suppression system for the Unit 1 auxiliary instrumentation room with the capability to maintain the design basis gas concentration of 50 percent in portions of the room for 15 minutes. The licensee entered the problem into their corrective action program. The finding is more than minor because it affects the Mitigating Systems cornerstone objective of ensuring reliability and capability of systems that respond to initiating events and the cornerstone attribute of protection against external factors, i.e. fire. The finding was determined to be of very low safety significance by a Significance Determination Process Phase 1 evaluation. Test records indicated a 50 percent CO2 concentration for 15 minutes in the lower half of the room and a 45 percent concentration for 15 minutes at three quarters of room height. This concentration was an acceptable amount to extinguish the most likely fire in this portion of the room. (Section 4OA3.5 | |
| 05000390/FIN-2008005-05 | 2008Q4 | Green | Licensee-identified | Licensee-Identified Violation | 10 CFR 55.25 states If, during the term of the license, the licensee develops a permanent physical or mental condition that causes the licensee to fail to meet the requirements of 55.21 of this part, the facility licensee shall notify the Commission, within 30 days of learning of the diagnosis, in accordance with 50.74(c). Contrary to the above, on October 21, 2008, the licensee discovered they had failed to notify the Commission within 30 days after one licensed operator had a permanent change in physical medical condition, as required by 10 CFR 55.25. This finding was evaluated using the traditional enforcement process because it impacted the Commissions ability to perform its regulatory licensing function. This finding was of very low safety significance because the medical condition was under control and had no impact on the individuals ability to perform licensed duties. The licensee entered this issue into their CAP as PERs 155159 and 155130 | |
| 05000390/FIN-2008005-06 | 2008Q4 | Green | Licensee-identified | Licensee-Identified Violation | TS 5.2.2.3, Administrative Controls Section, required that the Operations Superintendent shall have a valid senior reactor operators (SRO) license. During the time period of March 26, 2008, until October 17, 2008, the Operations Superintendent had an expired SRO license. This finding is of very low safety significance because the Operations Superintendent attended all required training and completed successfully all required examinations during the expired period. This issue was entered in the licensees CAP as PER 155152 | |
| 05000390/FIN-2008005-07 | 2008Q4 | Severity level Enforcement Discretion | NRC identified | Technical Specification for the Containment Gaseous Radiation Monitors | The inspectors identified a violation of TS 3.4.15, RCS Leakage Detection Instrumentation, for the licensees failure to maintain the gaseous lower containment atmosphere radioactivity monitor of the RCS leakage detection instrumentation operable. The monitor had been inoperable since May 2000 as a result of not being able to perform its safety function of detecting a reactor coolant pressure boundary leak of 1 gallon per minute (gpm) in one hour due to improvements in reactor fuel quality. The NRC is exercising enforcement discretion to not issue enforcement action for this violation in accordance with Enforcement Guidance Memorandum (EGM) 09-001, Dispositioning Violations of NRC Requirements for Operability of Gaseous Monitors for Reactor Coolant System Leakage Detection. On October 31, 2008, the inspectors, after consultation with the Office of Nuclear Reactor Regulation (NRR), informed the licensee that the gaseous lower containment atmosphere radioactivity was not operable. The licensee initiated PER 155844, declared the equipment inoperable, complied with the applicable actions of TS 3.4.15 which allowed up to 30 days of continued operation with compensatory actions in place, and submitted a license amendment request to change the TS. The TS amendment was issued on November 25, 2008, which removed the requirement to maintain the gaseous channel of the containment atmosphere radiation monitor as a method of RCS leakage detection. NRR determined that the technical bases for the gaseous lower containment atmosphere radioactivity monitor to be operable included sufficient sensitivity to detect a reactor coolant pressure boundary leak of 1 gpm in one hour. This sensitivity was consistent with the information provided in NRC Information Notice (IN) 2005-024, Nonconservatism in Leak Detection Sensitivity. This IN informed licensees that the 0.1-percent failed fuel assumption (original source term for sensitivity calculations) introduced a nonconservatism into the TS. However, the licensing bases for Watts Bar Unit 1 was not clear, in that, the licensing basis documents acknowledged that, for fuel with little or no defects, this sensitivity would not be expected. NRR considered that this circumstance would only occur immediately after initial plant startup. However, the licensee mistakenly concluded that the monitor would likewise be considered operable any time that fuel with little or no defects was again in use, e. g., due to improved fuel quality. In May 2000, the licensee developed calculation WBNTSR-062, Requirements for the Containment Upper and Lower Compartment Radiation Monitors, which concluded that for realistic RCS activity levels, the gaseous channel would not be capable of meeting the RG 1.45 detection sensitivity requirements. The UFSAR was revised to reflect this result and the change was submitted to the NRC as part of its normal periodic update. This conclusion was recently referenced in DCN 52631, dated June 20, 2008. In both cases, the licensee failed to recognize that not meeting the required sensitivity resulted in the gaseous lower containment atmosphere radioactivity monitors being inoperable. Contributing to the failure to recognize this issue in June 2008 was the licensees mistaken perception that since the NRC had been informed of the change by an UFSAR update, the change must have been acceptable. | |
| 05000390/FIN-2009002-01 | 2009Q1 | NRC identified | 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 | ||
| 05000390/FIN-2009002-02 | 2009Q1 | NRC identified | 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 | 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, 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-2009003-01 | 2009Q2 | Green | H.8 | NRC identified | Failure to Adequately Implement Procedures to Maintain the Design of the Intake Pumping Station Missile Shield | The NRC identified a Green, non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to adequately implement work order instructions to maintain the integrity of the intake pumping station (IPS) missile shield, as designed. The inspectors determined the licensees failure adequately implement work order instructions to maintain the integrity of the IPS missile shield was a performance deficiency. The failure to assure adequate tornado missile protection had a credible impact on reactor safety because of the potential exposure of both trains of the ERCW system to tornado induced damage. The inspectors reviewed Inspection Manual Chapter (IMC) 0612 and determined that the finding is more than minor because the finding was associated with the design control and protection against external events attributes of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated this finding using IMC 0609, Significance Determination Process, and determined that it was of very low safety significance (Green) given that the safety function of the ERCW system was not assumed to be completely failed or unavailable due to a severe weather initiating event. The finding directly involved the cross-cutting area of human performance under the procedural compliance aspect of the work practices component, in that, the work order instructions for restoration of the IPS missile shield after maintenance were not followed and the reliability and capability of the IPS missile shield was affected. (H.4.b). (Section 4OA2.2 |
| 05000390/FIN-2009003-02 | 2009Q2 | Green | Licensee-identified | Licensee-Identified Violation | TS 3.7.12 required that two trains of the Auxiliary Building Gas Treatment System (ABGTS) be operable in Modes 1, 2, 3, and 4 and during movement of irradiated fuel assemblies in the fuel handling area. Contrary to this, on May 28, 2009 the A train of ABGTS was found to be inoperable, and on May 30, 2009 the B train was also found to be inoperable. This was identified in the licensees CAP as PER 164765. This finding is of very low safety significance because it only represented a degradation of the radiological barrier function provided for the auxiliary building | |
| 05000390/FIN-2009004-01 | 2009Q3 | Green | H.2(a) H.6 | Self-revealing | Failure to Incorporate Existing Design Criteria Into Temporary Secondary Containment Boundary Doors | A self-revealing, non-cited violation (NCV) of 10 CFR 50 Appendix B, Criterion III, Design Control, was identified for failure to correctly translate the personal access door design basis into the specifications for the temporary ABSCE boundary doors installed to facilitate Unit 2 construction. As a result, the ABSCE boundary was disabled when the temporary doors (R002 and R003) failed during auxiliary building ventilation changes on May 27, 2009. The licensee entered the issue into the corrective action program as PER 172301, made door repairs to reestablish the ABSCE boundary, and took interim actions to minimize differential pressure across the temporary doors during auxiliary building ventilation changes. The licensees failure to utilize existing design criteria for doors R002 and R003 was a performance deficiency. The inspectors reviewed Inspection Manual Chapter (IMC) 0612 and determined that the finding was more than minor because, if left uncorrected, it would have the potential to lead to a more significant safety concern, specifically for loss of the secondary containment boundary. Additionally, the finding was associated with the design control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers, such as the secondary containment boundary, protect the public from radionuclide releases caused by accidents or events. Using the phase I screening worksheet of IMC 0609, the inspectors determined that the finding was of very low safety significance (Green) because it only represented a degradation of the radiological barrier function provided for the auxiliary building. The cause of the finding had a cross-cutting aspect in the area of human performance associated with the resources component. It was directly related to maintaining long term plant safety by maintenance of the design margins aspect of the resources component (H.2(a)). Specifically, the licensee did not utilize the existing design criteria for auxiliary building doors designated as air locks |
| 05000390/FIN-2009004-02 | 2009Q3 | Green | P.2 | Self-revealing | Inadequate Corrective Actions to Preclude Additional Temporary Secondary Containment Boundary Doors Failure | A self-revealing NCV of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure take prompt corrective actions to preclude repetition of the failure of the temporary auxiliary building secondary containment envelope (ABSCE) boundary doors installed to facilitate Unit 2 construction. Following the previous failure of temporary ABSCE boundary doors R002 and R003 during auxiliary building ventilation changes, the licensee initiated PER 172301 to determine the cause of the door failure. In accordance with licensee procedure PIDP-4, Corrective Action Program Screening and Oversight, PER levels are assigned based on the consequences of the identified condition and also on the frequency or probability of issue occurrence. Based on the condition classification guidance in Appendix A of PIDP-4, the door failures were considered by the licensee to be a Significant Condition Adverse to Quality (SCAQ), which required the associated PER to be designated as an A-level PER. Accordingly, PER 172301 was assigned as an A-level (highest category) requiring a root cause analysis and corrective actions to prevent recurrence. Corrective actions to prevent recurrence developed by the root cause team were not incorporated into plant procedures, and as a result, temporary doors (R002 and R003) failed during auxiliary building ventilation changes on June 27, 2009. The licensee entered the issue into the corrective action program as PER 175160, made door repairs to re-establish the ABSCE boundary, and shut the Unit 2 reactor building access doors to provide an additional ventilation barrier. The licensees failure to take corrective actions to preclude the temporary door failure repetition was a performance deficiency. The inspectors reviewed IMC 0612 and determined that the finding was more than minor because, if left uncorrected, it would have the potential to lead to a more significant safety concern, specifically for loss of the secondary containment boundary. Additionally, the finding was associated with the design control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers, such as the secondary containment boundary, protect the public from radionuclide releases caused by accidents or events. Using the phase I screening worksheet of IMC 0609, the inspectors determined that the finding was of very low safety significance (Green) because it only represented a degradation of the radiological barrier function provided for the auxiliary building. The cause of the finding had a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program component. It was directly related to the licensee thoroughly evaluating problems such that resolutions address the problems causes (P.1(c)). Specifically, during the investigation of the May 27, 2009, ABSCE door failures, the licensee failed to address the inadequate design of temporary doors R002 and R003 |
| 05000390/FIN-2009005-01 | 2009Q4 | Green | H.2 | NRC identified | Failure to Implement Analysis for Failed Auxiliary Charging Pumps | The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR 50.55a(f)(4) for the licensees failure to meet in-service test requirements for the 1B auxiliary charging pump. Between December 2008 and December 2009, licensee personnel tested the pump and determined that it was in the required action range. The licensee failed to either declare the pump inoperable until corrected or perform an analysis in accordance with program requirements. As part of their corrective action, the licensee performed an analysis of the pump, revised test procedures, and entered the issue into the corrective action program (CAP) as PER 211724. This finding was more than minor because if left uncorrected it has the potential to become a more significant safety concern. Specifically, the failure to adhere to equipment testing requirements could have allowed the loss of functional capability of the auxiliary charging pumps to exist without detection until the pumps were required to perform their designed safety function. The inspectors determined that the finding was of very low safety significance because the functional capability of the auxiliary charging pumps (ACPs) was not lost. The finding directly involved the cross-cutting area human performance under the supervisory and management oversight of work activities component, in that, the failures of the ACPs were left unresolved for an extended period of time over a number of failed tests. (H.4(c)) |
| 05000390/FIN-2009005-02 | 2009Q4 | Severity level IV | NRC identified | Failure to Adequately Update the UFSAR for the Removal of the Additional Diesel Generator Unit. | The inspectors identified an NCV of 10 CFR 50.71(e) for failure to adequately update the Updated Final Safety Analysis Report (UFSAR) to reflect that the additional diesel generator unit (ADGU) was never completed and made available for use as described in the UFSAR. The licensee entered these issues into the CAP as PER 175830. This finding was considered as traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. The inspectors used the NRC Enforcement Policy, Supplement I, to determine that the issue was more than minor because including references of incomplete equipment in the UFSAR would have a material impact on licensed activities associated with the onsite emergency AC power distribution system. This issue was considered a SL-IV violation because the inaccurate information was not used to make any change to the facility. No cross-cutting aspect was identified | |
| 05000390/FIN-2009005-03 | 2009Q4 | Green | Licensee-identified | Licensee-Identified Violation | 10 CFR 50.55a(g)(4) requires, in part, that pressurized water-cooled nuclear power facility components which are classified as ASME Code Class 1, Class 2, and Class 3 must meet the requirements set forth in ASME Section XI. ASME Code, Section XI, Subsection IWB, Article IWB-2500, Table IWB-2500-1, Item B5.10 requires a volumetric examination of all reactor vessel nozzle-to-safe end butt welds NPS 4 or larger each inspection interval. Contrary to this, the licensee failed to achieve the required examination coverage for eight welds during their 2005 examination effort due to a measurement discrepancy. This was identified in the licensees corrective action program as PER 203409. This finding is of very low safety significance because supplemental examinations performed in 2009 revealed no indications in the above welds | |
| 05000390/FIN-2009006-01 | 2009Q2 | Green | H.4 H.5 | Self-revealing | Failure to Promptly Correct a Condition Adverse to Quality Associated with the \'A\' Shutdown Boardroom Chiller | A self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI was identified for failure to take timely and effective corrective action to maintain the capillary line to the Essential Raw Cooling Water (ERCW) condenser water temperature control valve (1-TCV-67-158) filled with water to ensure operability of the A Shutdown Boardroom chiller. The licensee vented the line, returning the chiller to service, and entered the issue into their CAP. The finding is more than minor because it affects the Mitigating Systems Cornerstone objective of ensuring the availability of the A Shutdown boardroom chiller, which is a system that responds to initiating events. It is also associated with the cornerstone attribute of equipment availability and reliability. This finding was assessed using the Phase 1 screening worksheet of the SDP and determined to be of very low safety significance (Green) because it did not result in an actual loss of safety function of a single train for greater than the Technical Specification (TS) allowed outage time and was not potentially risk-significant due to external events. This finding has a cross-cutting aspect in the Work Control component of the Human Performance area (H.3(b)), because the licensee failed to properly prioritize the compensatory maintenance activities to support safety system operability of an operable but degraded system |
| 05000390/FIN-2009006-02 | 2009Q2 | Green | Self-revealing | Failure to Follow Plant Procedures for Canceling Preventive Maintenance | A self-revealing NCV of Technical Specification 5.7.1 was identified for the licensees failure to follow plant procedures which resulted in the failure of the Unit 1 Shield Building Vent Radiation Monitor System, an effluent radiation monitor. The inspectors determined the licensees failure to follow site procedures for PM cancellation was a performance deficiency and a finding. The inspectors reviewed Inspection Manual Chapter (IMC) 0612 and determined that the finding is more than minor because the finding is associated with the plant facilities/equipment and instrumentation attribute (reliability of process radiation monitors) of the radiation safety cornerstone (public radiation safety) and adversely affected the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian use. The finding was assessed using the IMC 0609, Appendix D, Public Radiation SDP, and because there was no failure to implement the effluent program, the finding was determined to be of very low safety significance (Green). No cross-cutting aspect was assigned to this finding because the direct cause was not considered indicative of current performance | |
| 05000390/FIN-2010002-01 | 2010Q1 | Green | H.4 H.5 | NRC identified | Failure to Assure that Test Requirements Were Satsified Following a Design Change | The inspectors identified a violation of very low safety significance and an associated non-cited violation of 10 CFR 50 Appendix B Criterion XI, Test Control, for the licensees failure to assure that test requirements were satisfied following a design change affecting the unit 2 channel III (2-III) safety-related vital AC board. As a result, the 2-III vital AC board was returned to service with post modification test (PMT) acceptance criteria not being met; leaving a non-conforming transfer switch on the 2-III vital AC board. The licensee entered this issue into the corrective action program as PER 215224.The inspectors reviewed IMC 0612 and determined that the finding was more than minor because the finding would have the potential to lead to a more significant safety concern if left uncorrected, in that, failing to ensure that PMT acceptance criteria are met could allow risk significant equipment to unknowingly be returned to service in a degraded condition. This finding was evaluated using the significance determination phase 1 screening criteria and was determined to be of very low safety significance because the finding did not represent an actual loss of safety function of a single train of equipment for greater than its technical specification allowed outage time. The cause of the finding had a cross-cutting aspect in the area of human performance associated with the work control component. It was directly related to the licensee appropriately coordinating work activities by incorporating actions to address the impact of changes to the work scope on the plant H.3(b). Specifically, when faced with an unexpected failure of the PMTI as written, the licensee failed to restore the 2-III transfer switch to its design basis condition following maintenance. As a result, a non-conforming switch, revealed during design change testing, was placed into service. |
| 05000390/FIN-2010002-02 | 2010Q1 | Green | H.13 | Self-revealing | Failure to Establish Adequate Instructions or Procedure for Determining Vital Inverter Frequency | A self-revealing, non-cited violation (NCV) of TS 5.7.1, Procedures, was identified for the licensees failure to properly implement SPP-2.2, Standard Programs and Processes Administration of Site Technical Procedures. Specifically, while performing vital inverter frequency verifications required by TS surveillance3.8.7.1, the licensee failed to take the actions specified in SPP 2.2 to implement a procedure change or write a new procedure when the surveillance could not be performed as written. As a result, the output of the unit 2 channel II safety-related vital inverter was short-circuited when improperly selected test equipment was connected across the inverters installed frequency meter. The short circuit condition damaged a power diode in the inverter circuit and caused annunciator fuses and the600 amp inverter power fuse to blow. The inverter automatically transferred to its nonbattery-backed bypass supply. The licensee entered the issue into the corrective action program as PER 212143.The inspectors reviewed IMC 0612 and determined that the finding was more than minor because the finding would have the potential to lead to a more significant safety concern if the licensees failure to work within the established work control process was left uncorrected. The finding was evaluated using the significance determination phase 1 screening criteria and was determined to be of very low safety significance because the finding did not represent an actual loss of safety function of a single train of equipment for greater than its TS-allowed outage time. The cause of the finding had a cross-cutting aspect in the area of human performance associated with the decision-making component. It was directly related to licensee making safety-significant or risk-significant decisions using a systematic process, especially when faced with uncertain or unexpected plant conditions, to ensure safety is maintained H.1(a). Specifically, when it was determined the surveillance instruction could not be performed as written, the licensee did not use the established work control or procedure change processes in support of making the decision to substitute use of M&TE for the failed frequency meter. |
| 05000390/FIN-2010002-03 | 2010Q1 | Severity level IV | NRC identified | Failure to Submit Complete and Accurate Information for a Requested License Amendment | The inspectors identified an NCV of 10 CFR 50.9(a), Completeness and Accuracy of Information, when the licensee failed to submit complete and accurate information for License Amendment 77 (LA 77) related to the permeation of the Tritium Producing Burnable Absorber Rods (TPBARS) when pertinent information became available to the licensee prior to the issuance of LA 77. The licensee has entered this item into its corrective action program as PER 210845This finding was considered as traditional enforcement because the failure to provide complete and accurate information impacted the regulatory process. This finding was determined to be minor because the licensee configured the core TPBAR loading in a conservative manner. However, due to a lack of completeness of information provided by the licensee to the NRC, the NRC approved LA 77 which gave the licensee allowance to change the configuration of core TPBAR loading which the NRC may not have otherwise allowed. The lack of completeness impeded the NRC regulatory process. Consistent with the guidance in Section IV.A.3 and Supplement VII, Paragraph D.1 of the NRC Enforcement Policy, this finding was determined to be a Severity Level IV non-cited violation. | |
| 05000390/FIN-2010003-01 | 2010Q2 | Green | H.4 H.5 | NRC identified | Failure to Assure that Adequate Test Requirements Were Developed and Implemented Following a Repair | The inspectors identified a NCV of TS 5.7.1, Procedures, for the licensee failing to develop and implement an adequate post-maintenance test procedure for valve 0-CKV-067-0502C, air release valve for C ERCW pump, resulting in the valve not being fully tested following rebuild per work order (WO) 07-820358-000. The licensee entered these issues into the corrective action program as PER 228680 The licensees failure to develop and implement an adequate post-maintenance test was determined to be a performance deficiency. The performance deficiency was determined to be more than minor, and therefore a finding, because it would have the potential to lead to a more significant safety concern if left uncorrected, in that, failing to ensure that adequate procedures are developed and implemented could allow risk-significant equipment to unknowingly be returned to service in a degraded condition. This finding was evaluated using the Significance Determination Process Phase 1 screening criteria and was determined to be of very low safety significance because the finding did not represent an actual loss of safety function of a single train of equipment for greater than its TS allowed outage time. The cause of the finding had a cross-cutting aspect in the area of human performance associated with the work control component. It was directly related to the licensee appropriately coordinating work activities by incorporating actions to address the impact of changes to the work scope on the plant (H.3(b)). Specifically, personnel failed to recognize the impact of changing the scope of the PMT. As a result, an inadequately tested valve was placed into service. |
| 05000390/FIN-2010003-02 | 2010Q2 | Green | H.11 H.12 | Self-revealing | Lack of Procedure Implementation Results in 1B EDG being started with 15 Cylinder Plugs Open | A self-revealing, non-cited violation (NCV) of Technical Specifications (TS) 5.7.1, Procedures, was identified for the licensees failure to adhere to OPDP-1, Conduct of Operations, Section 5.1, Procedure Adherence, resulting in the 1B Emergency Diesel Generator being returned to service with 15 cylinder valves open. The licensee entered this issue into the corrective action program as problem evaluation report (PER) 232018. Failing to ensure that safety-related equipment was properly returned to service was a performance deficiency. The performance deficiency was determined to be more than minor, and therefore a finding, because it was associated with the human 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 (i.e., core damage). The finding was evaluated using the Significance Determination Process Phase I and was determined to be a finding of very low safety significance because the valve mispositioning was found and corrected in less than the TS allowable outage time. The cause of the finding was directly related to the crosscutting area of the human performance, error prevention aspect of the work practices component, in that, the licensee failed to ensure that personnel did not proceed in the face of uncertainty when one of the cylinder valves was determined to be in the incorrect position (H.4(a)). |
| 05000390/FIN-2010003-03 | 2010Q2 | NRC identified | B-train Main Control Room Chiller Temperature Control Valve Failure | The inspectors identified an issue associated with the B-train Main Control Room Chiller temperature control valve. This issue is being characterized as an unresolved item (URI). Licensee procedure 0-SI-82-4, 18 Month Loss of Offsite Power with Safety Injection Test Diesel Generator 1B-B, provides the detailed steps to verify the operability of Diesel Generator 1B-B and 6.9 kV Shutdown Board 1B-B load shed logic during loss of offsite power with and without safety injection (SI) actuation. 0-SI-82-4 also simulates a loss of offsite power and the subsequent recovery of shutdown board power from the 1B-B diesel generator. One of the components affected during surveillance 0-SI-82-4 was the B-train main control room chiller. During the test, the chiller was initially in service with normal ERCW cooling flow supplied. When shutdown board voltage was lost during the test, the B-train main control room chiller stopped and B-train ERCW header flow ceased and ERCW pressure lowered to atmospheric pressure. The main control room chiller temperature control valve (TCV), 0-TCV-67-1053-B, was a hydraulically operated valve that used ERCW pressure for operation. Due to valve design, the TCV opened on the loss of ERCW pressure. When the shutdown board was re-energized from the diesel, the diesel load sequencer started the associated ERCW pumps and the main control room chiller. During the performance of 0-SI-82-4 on March 10, 2008, the B-train MCR chiller tripped on low suction pressure. Subsequent licensee investigation revealed that the chillers TCV had failed in the open position. The licensee initiated a work order to repair the TCV and PER 139875 to document the chiller trip during testing. During TCV disassembly, the licensee discovered that the valves internal stem guide had become misaligned which prevented the valve from closing. No valve internal parts were found damaged in the valve body or actuator. The corrective actions for PER 139875 included completion of the work order to rebuild the TCV and completion of the maintenance rule cause determination evaluation (CDE). CDE 914 determined that the apparent cause of the shift of the TCVs valve stem guide was due to an ERCW header pressure surge which occurred when the ERCW pumps restarted after the simulated loss of offsite power during 0-SI-82-4. The CDE also determined that no actions to prevent recurrence were necessary since the testing on March 10, 2008, was considered to be a unique, isolated event that was caused by a peculiar ERCW transient which is unlikely to be repeated in future testing or any other anticipated plant condition. During the performance of 0-SI-82-4 on October 9, 2009, the B-train MCR chillers TCV failed open. The licensee initiated a work order to repair the TCV and PER 204181 to document the chiller trip during testing. During TCV disassembly, the licensee discovered that the valves internals had shifted therefore preventing the valve from closing. No valve internal parts were found damaged in the valve body or actuator. On December 23, 2009, the functional evaluation for PER 205438 determined that the B-train MCR chiller TCV was operable, but non-conforming, and that manual compensatory actions were required. The manual compensatory actions prescribed by the functional evaluation were implemented by revision to licensee procedure AOI-40, Station Blackout. The inspectors questioned the licensees compensatory action implementation and past operability of the MCR chillers. Pending additional information from the licensee regarding the past operability determinations and further review of the maintenance on the TCVs by the NRC, this issue will be identified as URI 05000296/2010003-01, B-train Main Control Room Chiller Temperature Control Valve Failure. | ||
| 05000390/FIN-2010003-04 | 2010Q2 | Green | Licensee-identified | Licensee-Identified Violation | Criterion V, Instructions, Procedures, and Drawings requires, in part, that instructions, procedures, or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, on April 7, 2010, the licensee identified terminal screws in solid state protection system (SSPS) cabinets 2-R-48 and 2-R-51, which affected emergency diesel generators (EDGs) 2A-A and 2B-B, had been replaced with isolating plastic screws and washers. This occurred in January 2010 under Unit 2 WOs 09-954447-000 and 09-954448-000 which directed the installation of plastic screws and washers in 2-R- 48 and 2-R-51. The result was that the Unit 2 diesel generators output breakers would not open if a Safety Injection (SI) signal on Unit 1 was initiated while in parallel with its associated shutdown board during EDG 2A-A and 2B-B testing conditions. Corrective actions are documented in PER 224586. This finding is of very low safety significance because the Unit 2 EDGs are lightly loaded during a Unit 1 Safety Injection and the condition only applies while the EDGs are operating in parallel with offsite power (e.g. monthly surveillance procedures). | |
| 05000390/FIN-2010004-01 | 2010Q3 | Green | Licensee-identified | Licensee-Identified Violation | Facility Operating License NPF-90 for Watts Bar Nuclear Plant Unit 1, Condition 2.F, requires that TVA shall implement and maintain in effect all provisions of the approved fire protection program as described in the Fire Protection Report (FPR). Contrary to the above, on August 18, 2010, the licensee identified a failure to comply with the fire barrier sealing requirements of the FPR when two three-inch conduit penetrations were determined to be improperly sealed in the two-hour fire barrier separating the 2B 480V transformer room from the unit 2 south valve vault room. Upon identification of the degraded penetrations, the licensee established the required compensatory fire watches until the penetrations were properly sealed. This was identified in the licensees CAP as PER 245285. This finding was of very low safety significance in accordance with IMC 0609, Appendix F, Attachment 1, Fire Protection SDP Phase 1 Worksheet, because the fire barrier was only moderately degraded and there were no fixed or in-situ fire ignition sources that would subject the degraded fire barrier to direct flame impingement. | |
| 05000390/FIN-2010004-02 | 2010Q3 | Green | Licensee-identified | Licensee-Identified Violation | Technical Specification 3.3.1 provides required actions for removing Power Range detector channels from service while in Modes 1 and 2. Required action D.2.2 requires that SR 3.2.4.2, verification of QPTR within limit using either the movable incore detectors or the PDMS, Power Distribution Monitoring System, within 12 hours when power level greater than 75 percent. Contrary to the above, with reactor power at 100 percent RTP, power range detector N44 was removed from service for greater than 12 hours without performing required action D.2.2. Specifically, with the PDMS out of service, a flux map with the moveable incore detector system was not performed. This was identified in the licensees CAP as PER 254334. This finding was of very low safety significance in accordance with IMC 0609, Attachment 4, SDP Phase 1, Table 4.1, Characterization Worksheet, because the flux tilt was within specification before and after the timeframe that the PDMS was out of service with no rod motion during the timeframe. | |
| 05000390/FIN-2010005-02 | 2010Q4 | Green | NRC identified | 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 | Green | NRC identified | 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. | |
| 05000390/FIN-2010006-01 | 2010Q2 | Green | NRC identified | 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 | NRC identified | 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 | ||
| 05000390/FIN-2010007-01 | 2010Q4 | NRC identified | Use of Omas Potentially Not Consistent with the Fire Protection Licensing Basis | The inspectors opened an unresolved issue (URI) pending NRC review of recently-received requested information related to questions regarding the licensee compliance with all provisions of their approved FPP. Specifically, the inspectors requested information regarding the licensees reliance and use of post-fire OMAs that may have not been approved by the NRC in SSERs 18 or 19. In SSER 18, the NRC approved certain post-fire OMAs used to compensate for fire-induced equipment failures. The licensee calculation WBN-OSG- 165, Rev. 5, Manual Actions Required for Safe Shutdown Following a Fire, which was referenced in SSER 18, section 3.5, identified OMAs credited for achieving and maintaining safe shutdown conditions for certain fire events. In this calculation, the licensee identified the OMAs which needed to be accomplished to achieve safe shutdown, established time requirements to accomplish these OMAs, and quantified expected completion times for performance of these OMAs. The licensee credited the use of Abnormal Operating Instruction (AOI 30.2) as its post-fire safe-shutdown procedure per SSER 18, section 3.5.1, Safe-Shutdown Procedures and Manpower. The inspectors identified at least two instances, one onsite and one in-office, where OMAs were not listed in the calculation WBN-OSG-165, Rev. 5. In the first instance, inspectors reviewed credited post-fire operator actions implemented in AOI 30.1, Plant Fires, Rev. 9, Step 5, and AOI 30.2, Fire Safe Shutdown, Rev. 27, Step 10. The inspectors found that these actions did not appear to have been analyzed in Rev. 5 of calculation WBN-OSG-165. Therefore, these OMAs may not have been reviewed and approved by the NRC. These actions were brought to the licensees attention October 6, 2010. The licensee provided an initial response to NRC questions related to these actions on October 7, 2010. Based upon NRC comments, the licensee provided additional information to the inspectors related to these OMAs on December 6, 2010. On December 22, 2010, based upon these responses and review of information, the NRC inspectors requested the licensee to provide a list of all OMAs implemented in lieu of meeting 10 CFR Part 50, Section III.G.2, after SSER 18 was issued, as well as the supporting analyses. After several conference calls, on April 5, 2011, the licensee provided a spreadsheet titled, Watts Bar Nuclear Plant Manual Operator Actions (MOAs) Developed For and After Revision 6 of Calculation WBN-OSG4-165 (06/30/1995). The licensee stated that information provided included the list of all OMAs implemented after issuance of SSER 18. The inspectors reviewed the information and found that the OMAs identified during the onsite portion of the inspection were not included, nor did the list include the associated evaluations. On April 15, 2011, as a result of NRC review and additional questions, the licensee stated that some of the OMAs they listed in their April 5, 2011, response were added June 6, 1995, before Rev. 5 of calculation WBN-OSG-165 and SSER 18 was issued. On a follow-up call to the license conducted June 13, 2011, licensee personnel stated the OMAs identified in AOI 30.1, Plant Fires, Rev. 9, Step 5, and AOI 30.2, Fire Safe Shutdown, Rev. 27, Step 10 were done so in response to NRC Information Notice (IN) 89-52, Potential Fire Damper Operational Problems. In the second instance, the inspectors identified seven OMAs which appeared to be added after WBN-OSG-165, Rev. 5. This was based upon the review of information provided to inspectors on April 5, 2011. The inspectors determined that Rev. 5 of calculation WBN-OSG-165 became effective May 3, 1995, and the seven OMAs were added June 30, 1995. On June 13, 2011, the inspectors conducted a follow-up call with the licensee and were provided additional information. Specifically, licensee personnel stated that the seven OMAs were added via a design change before SSER 18 was issued to the licensee in October 1995; however, were not included in calculation WBNOSG- 165. The licensee personnel stated these additional OMAs were added to the FPR in revisions 3 & 4. Pending review of this additional information, this issue will remain open as unresolved item (URI) 05000390/2010007-001, Use of OMAs Potentially Not Consistent with the Fire Protection Licensing Basis. | ||
| 05000390/FIN-2010007-02 | 2010Q4 | NRC identified | INSTALLED INSULATING FLUID IN INTERIOR TRANSFORMERS POTENTIALLY DEVIATES FROM LICENSE/DESIGN CRITERION IN SSER 10 AND POSITION D.1.g OF APPENDIX A TO BTP (APCSB) 9.5-1 | The inspectors opened an URI related to questions regarding the licensees compliance with all provisions of their NRC-approved FPP. Specifically, the inspectors raised questions regarding the dielectric insulating liquid used for indoor power transformers as specified Appendix FF, Section 5.10.2 of SSER 18 and NRC Position D.1.g of Appendix A to BTP APCSB 9.5-l, Guidelines for Fire Protection for Nuclear Power Plants, dated August 23, 1976. Fire Area FA 37 (AV-064) contained four liquid-insulated 6.9kV to 480V shutdown board transformers, in groups of two inside containment curbs. These medium voltage transformers were insulated with a silicone-type dielectric insulating fluid. Three of the four transformers (1-OXF-212-A2-A, 1-OXF-212-A1-A, and 1-OXF- 212-A-A) contained an estimated 317 gallons of insulating fluid and the other transformer (0-OXF-206-A) contained approximately 205 gallons. Near these transformers were combinations of redundant safety-related cable trays or conduits or both. While performing the review of FA 37 (AV-064), the inspectors identified the indoor power transformers dielectric insulating liquid was not consistent with that described in SSER 18, section 5.10.2, Askarel-Insulated Transformers and NRC Position D.1.g of Appendix A to (BTP) APCSB 9.5-l, Guidelines for Fire Protection for Nuclear Power Plants. Section 5.10.2 of SSER 18 specified that indoor transformers would be either a dry type or insulated with non-combustible liquid. Section 5.10.2 of SSER 18 further stated that Askarel was used as the noncombustible liquid for indoor transformers. The inspectors determined that the SSER reference was based on transformer insulating liquid being noncombustible material (negligible combustible loading) which did not represent an ignition source. However, during the inspection the inspectors found that the transformers in FA 37 did not contain the specified dry type or non-combustible dielectric insulating material, but were insulated with a silicon-based combustible dielectric liquid. Furthermore, Position D.1.g. (ii) of Appendix A to (BTP) APCSB 9.5-l specified that safety related systems that are exposed to flammable oil-filled transformers should be protected from the effects of a fire by enclosing the transformer with a three-hour fire barrier and installing an automatic water spray protection. The transformers had not been enclosed with such a barrier. The inspectors reviewed Part VI of the WBN FPR (Revision 39) and found that the fire rating of the regulatory barriers for the floor and walls in FA 37 was two-hours. The inspectors also reviewed WBN FPR, Part 1, Table 1-1, Summary of Fire Protection Conformance, (Revision 27) which specified that safe shutdown equipment cables were located in FA 37 and were protected with a credited one-hour rated fire resistive wrap. Table 1-1 of the FPR also identified that the area total fixed combustible load fire severity for a 3-hour rated barrier was classified as Moderately Severe, e.g., less-than 240,000 Btu/ft2. The inspectors reviewed the combustible loading summary calculationEPM-DOM-012990, (Revision 41) for FA 37 and found that the fuel load in the area was 164,549 Btu/ft2, which exceeded the 2-hour rated barrier criteria of 160,000 Btu/ft2. Additionally, the review of WBN FPR, Part VII, Deviations and Evaluations, (Revision 10) noted that the licensees evaluation for deviation 2.4 concerning intervening combustibles did not specifically consider the transformers in the area (insulated with a combustible dielectric liquid) as a potential intervening combustible located between redundant components. The licensee was not able to provide a documented technical evaluation which justified the use of the combustible dielectric insulating liquid and its associated contribution to the area combustible load fire severity or intervening combustible evaluation. In response to the inspectors questions, the licensee stated that, although SSER 18 did address Askarel oil, no additional evaluations of the type of oil used in indoor transformers was required since the SSER did not reflect the latest information provided by TVA in Revisions 4 and 5 of their FPR submitted to NRC on September 28, 1995, and November 1, 1995, respectively. The licensee stated that these submittals identified that transformers installed within safetyrelated buildings are either dry-type or insulated and cooled with high fire point (650F) liquid. Based upon the review of the WBN FPR and EPM-DOM-012990, the inspectors concluded that the transformers in the area (insulated with a combustible dielectric liquid) contributed to a total fixed fuel load fire severity that exceeded the credited fire resistive rating of the room fire barriers and could potentially challenge either the credited one-hour barrier for the safety related cables, the walls separating the adjacent FAs or both. The inspectors discussed this issue further with licensee personnel on June 13, 2011 during a teleconference. The licensee personnel stated they would provide additional information related to questions raised by inspectors regarding when the change to the combustible dielectric was made. Based upon questions raised by the inspectors, 40 additional indoor transformers were identified in Unit 1 and areas of Unit 2 (under construction) to have the same combustible dielectric liquid and located within ten (10) additional AVs (AV-1, AV-51, AV-63, AV-64, AV-68, AV-69, AV-89, AV-94, AV-95, and AV-96) at WBN. The licensee initiated service request (SR) 263312 and problem evaluation report (PER) 265331 to address the issues described in this section. Further review and consultation with NRC experts in the Office of Nuclear Reactor Regulation will be needed to determine the regulatory impacts of this issue. As a result, this issue is identified as URI 05000390/2010007-002, Installed Insulating Fluid in Interior Transformers Potentially Deviates from License/Design Criterion in SSER 18 and Position D.1.g of Appendix A to BTP (APCSB) 9.5-1. | ||
| 05000390/FIN-2010007-03 | 2010Q4 | NRC identified | Questions Related to OMA to Establish RCP Seal Cooling in the Event of a Fire in AV-076, Computer Room | The inspectors opened an URI involving an OMA credited for establishing (RCP) seal cooling. Specifically, a hand-wheel on a valve required by procedure to be closed in the event of a fire in the control building, FA 48 (AV-076), was missing. The licensee maintained that the action, if not performed, would not have an effect on their ability to achieve and maintain safe shutdown. This item is pending further inspector review. In the event of a fire in AV-076, procedure AOI-30.2 C69, Fire Safe Shutdown Control Building, directed operators to establish RCP seal injection via air-operated valve 1-FCV-62-93. While performing a field walk-down of procedure AOI-30.2 C69, the inspectors identified that Step 4 of Auxiliary Unit Operator Checklist 1 could not be completed as directed, because the hand wheel for valve 1-ISV-32-2934 was missing. Valve 1-ISV-32-2934 is a manual air isolation valve on a 34 inch airline to air-operated valve 1-FCV-62-93. The procedure directed the operator to close valve 1-ISV- 32-2934 to isolate air to valve 1-FCV-62-93, and open the petcock on the regulator for valve 1-FCV-62-93 to bleed off the air, which forced valve 1-FCV-62-93 to fail open. This would allow charging flow to the RCP seals to be controlled by the seal water injection filter via a series of manually-operated valves. This would also provide makeup to the RCS since the primary injection path would be isolated. The inspectors identified that the last time valve 1-ISV-32-2934 was operated was on February 23, 2008, per Work Order WO 07-816218-000. The licensee staff initially told the NRC inspectors that this manual action was not required for SSD. Inspectors requested an evaluation of the impact of the failure to perform this manual action on the ability to achieve and maintain SSD. Upon identification of the missing hand-wheel on October 8, 2010, the licensee initiated Service Request SR-262219 to replace the missing hand-wheel. On October 20, 2010, the inspectors requested a copy of the corrective action documents for the missing hand-wheel, and were told that the service request had been closed to a work order which was still open. As a result, the hand-wheel had not been replaced. The licensee informed the inspectors that in accordance with their corrective action program, a PER should have been initiated for this issue. The licensee then initiated SR 269706 to address the failure to write a PER and untimely replacement of the hand-wheel. The hand-wheel was replaced by licensee staff on October 30, 2010, per WO 11524638. The licensee had not established compensatory measures for the time period the hand wheel was missing, because tools were available in an Operations personnel cabinet for individuals to use. However, the need to obtain the necessary tools to manually close valve 1-ISV-32-2934 was not discussed in procedure AOI-30.2 C69 or evaluated to determine if extra time was available to obtain the tools. On October 22, 2010, inspectors requested information on the effect on SSD if the action was not completed successfully, the fire areas where the action was credited, and the design basis impact if the RCP seal cooling flow criteria was not met. The licensee staff provided a response to the inspectors on November 8, 2010, in which they indicated that RCP seal injection flow rates would be adequate without closing valve 1-ISV-32-2934. As a result of reviewing this information the inspectors requested additional information regarding seal injection flow rates and the effect on the pressurizer. The licensee provided additional information to NRC on December 1, 2010. A conference call with the licensee was conducted on February 24, 2011, to discuss a discrepancy between the licensees November 8, 2010, response and calculation WBNOSG4- 031. On March 24, 2011, the licensee provided clarifying information to the inspectors related to this issue. Pending NRC review of all information this issue is identified as URI 05000390/2010007-003, Questions Related to OMA to Establish RCP Seal Cooling in the Event of a Fire in AV-076, Computer Room. |