Semantic search
Jump to navigation
Jump to search
| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000338/FIN-2011005-03 | 2011Q4 | North Anna | Adverse Changes to the Fire Prottection Program Involving Inadequate Control of Transient Combustibles | The inspectors identified a Severity Level IV Non-cited Violation (NCV) of the North Anna Power Station, Unit 1 and Unit 2 Renewed Facility Operating Licenses, NPF-4 and NPF-7, Condition 2.D, Fire Protection Program (FPP) for making a change that adversely affected their ability to achieve and maintain safe shutdown. This led to inadequate controls of transient combustibles. The licensee initiated condition reports CR342754, Failed to submit request for transient fire loading in U- 2 safeguards, CR 397441, Appendix R fire wrap in Unit 2 Containment, and CR 396368, Appendix R fire wrap in Unit 1 Containment. The inspectors determined that the changes to the FPP involving the control of transient combustibles was a violation involving traditional enforcement because it impacted the NRCs ability to perform its regulatory function. The finding was determined to be more than minor because the relaxation of transient combustible controls described in the revisions to VPAP-2401, constituted a change which adversely affected the licensees ability to achieve and maintain safe shutdown in the event of a fire. This violation is characterized at Severity Level (SL) IV in Supplement I of the NRC Enforcement Policy, in that actual fire did not occur, and the potential consequences were limited given that defense in depth was maintained with the existence of automatic fire detection and suppression capability and the availability of fire response teams. Although the licensee failed to meet regulatory requirements that have more than minor safety or environmental significance, the inspectors were unable to confirm the introduction of excessive transient combustibles into the plant other than the problem identified on July 27, 2009. This lack of information was due to the licensee FPP changes that did not require a permit for evaluation and documentation. Because the issue is in the licensees corrective action program as CR382725, this violation is being treated as an NCV, consistent with the NRC Enforcement Policy. This violation was not screened for associated cross-cutting aspects because it dealt with traditional enforcement |
| 05000338/FIN-2011005-01 | 2011Q4 | North Anna | Failure to Follow Procedure to Ensure Proper Calibration of RHR Valve Control Circuit | A self-revealing Green NCV of Technical Specification 5.4.1.a was identified for the licensees failure to implement procedures as required by Regulatory Guide 1.33, Appendix A, Section 8, Procedures for Control of Measuring and Test equipment and for Surveillance Tests, Procedures, and Calibrations, specifically calibration procedures for a control circuit associated with a residual heat removal (RHR) suction valve. The licensee entered this issue into their corrective action program as CR452756 2-RH-MOV-2700 will not open with proper pressure across the seat and properly calibrated the control circuit. The inspectors determined that the failure to use the appropriate test point as required by licensee procedure 2-ICP-RC-P-2402 for the calibration of comparator card PC-2402 C1-245 was a performance deficiency. The inspectors reviewed IMC 0612, Appendix E and determined the finding was more than minor because it was similar to example 4.c. In accordance with NRC Inspection Manual Chapter (IMC) 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, Checklist 4, the inspectors conducted a Phase 1 SDP screening and determined the finding required a Phase 2 analysis because the calibration error degraded the licensees ability to recover DHR once it was lost. A phase 2 SDP evaluation was performed by a regional SRA in accordance with NRC IMC 0609 Appendix G, Attachment 2, Phase 2 SDP Template for PWR during Shutdown. The exposure time was < 1 day from when RHR was secured and the valve closed until the licensee restored normal function for the valve. The significant assumptions and influential factors affecting the risk included: (1) The PD only affected opening from the main control room, local manual operation was not affected, (2) Closing of the valve and valve position indication were not affected, (3) Procedural guidance existed for local manual operation, (4) RCS pressure remained low (380psig) during the exposure period, and (5) the plant had been shutdown since August 23, 2011, and decay heat was very low. Large Early Release Fraction (LERF) risk was not significant due to the exposure period existing long after shutdown. The result of the risk analysis was an increase in core damage frequency of < 1E-6 per year, a GREEN finding of very low safety significance. The cause of this finding involved the cross-cutting area of human performance, the component of work practices, and the aspect of human error prevention, H.4(a) because the licensee failed to utilize the human performance tool of self-checking when completing the calibration of comparator card PC-2402 C1-245. |
| 05000338/FIN-2011011-02 | 2011Q4 | North Anna | Failure of 2H Emergency Diesel Generator Jacket Water Cooling Gasket Resulting in Inoperability during Dual Unit LOOP | To adequately evaluate the performance of the EDGs in response to the seismically induced LOOP (including the 2H EDG coolant leak and any identified anomalies), the team performed the following activities: FnConducted walk-downs of the EDGs to evaluate the material condition FnConducted interviews with plant personnel (maintenance, engineering, and operations; root cause investigation team) to determine an accurate account of events related to the EDGs FnReviewed design and engineering documents to verify appropriateness of licensee actions in accordance with design and licensing basis FnObserved corrective maintenance and testing to assess the licensees actions to restore the EDGs In addition, the team reviewed corrective action CRs to evaluate the licensees response to identified deficiencies associated with the EDGs. The vendor manual was referenced to verify alignment with licensee maintenance procedures. Industry operating experience was referenced to identify any potential generic industry issues similar to what was observed at North Anna with respect to the EDGs performance. The team found some issues with EDG performance and identified two URIs that are described in this section. Following the seismic event on August 23, 2011, at 1:51 p.m., all four EDGs started and loaded their respective emergency buses due to a loss of offsite power on both units. About 45 minutes after the EDGs started, a coolant leak was observed on the 2H EDG. At 1:40 p.m., the 2H EDG was manually tripped and secured and the associated emergency bus de-energized. The 2H emergency bus was subsequently re-energized by the SBO diesel. Additionally, the 1J EDG was observed to have minor frequency oscillations. This issue is discussed in further detail in Section 6.0 of this report. Upon further investigation, it was determined that the 2H EDG coolant leak was caused by failure of a fiber gasket located between the exhaust belt and the jacket water cooling inlet jumper on the opposite control side (OCS) of the diesel engine. Initial discovery found the gasket soft and extruding from the flange edge. Due to the excessive coolant leak and in response to a High Jacket Coolant Temperature annunciator that came in during the event, the licensee inspected the cylinder liners, pistons, and rings for damage. No engine damage was found to have occurred. During restoration of the 2H EDG, a small exhaust leak was also identified during the post-maintenance test. The licensee subsequently replaced one exhaust gasket and the extension pipe. The small leak did not have an impact on the EDG to perform its safety function. In May 1999, EDG vendor Fairbanks-Morse issued a Marketing Information Letter, Vendor Technical Manual (VTM) Addenda 72, detailing a new, fiber gasket to replace the previous rubber gaskets for the cooling water bypass fittings. The licensee began installation of the new gaskets in 2001. One major difference was the new fiber gasket was 1/8 thick as opposed to 1/16 for the rubber gasket. The letter also provided recommendations for gasket installation. These recommendations included: FnAllowing a minimum dry time of 10 minutes following application of the gasket adhesive; FnEnsure the fitting surfaces for the exhaust belt and the water inlet flange have the appropriate finish; FnAssemble fitting to exhaust belt and torque nuts to 70 ft/lbs +/- 10 Maintenance procedure, 0-MCM-0701-27, Replacement of Emergency Diesel Generator Cylinder Liners, Revision 19, was used for replacement of the gaskets on 2H EDG in May 2010. The procedure did not include a dry time following application of the adhesive (RTV). Improper curing time for the adhesive could impact the proper alignment of the gasket; too short a time can allow the gasket to move out of place, too much time can harden the adhesive. Following overhaul of the 2H EDG in May 2010, which included replacement of the gaskets, the licensee performed a hydrostatic test to ensure proper restoration. During this test, water pressure was applied (at approx. 50 psi) to the engine block above the normal operating pressure (approx. 30 psi) to ensure no external leakage was occurring; however, coolant leakage was observed on all of the gaskets. It was determined at this time, as documented in Condition Report (CR) 383161 and Corrective Action (CA) 172549, that the RTV adhesive should be allowed to set for 30 V 60 minutes on the gaskets prior to installation for improved sealing. The 2H EDG gaskets were removed and re-installed and passed a subsequent hydrostatic post maintenance test. A subsequent revision to the procedure was approved and implemented in September 2010 to include the adhesive cure time. When the 2H EDG was taken out of service for corrective maintenance following discovery of the coolant leak on August 23, 2011, the licensee removed the OCS heat shields and stress bars, drained the remainder of the coolant, and removed the exhaust components as necessary to gain access to the jacket water inlet elbow. Initial inspection of the water by-pass inlet revealed the gasket protruding past the inlet fitting indicating that the gasket might not have been properly aligned when originally installed in May 2010, despite having been installed twice and satisfactory completion of the hydrostatic testing. Additional investigation by the licensee revealed that in addition to potential misalignment of the water bypass inlet gasket, the jacket water bypass inlet header adjustable screw and jam nut were potentially inappropriately installed. The adjustable screw and jam nut act as a cantilever on the engine block and bypass inlet fittings. Excessive tightening of the adjusting screw can place more compression on the top of the gasket and cause the gasket to extrude and leak on the bottom of the inlet pipe joint. There was no guidance in procedure 0-MCM-0701-27 for tightening the adjustment screw and jam nut; the procedure has since been revised to include detailed instructions. Following installation of the gaskets in May 2010, 0-MCM-0701-27 required the water bypass fitting bolts be torqued to 50 -55 ft-lb; however, this was in conflict with the vendor recommended 70 Ft.-lbs. as outlined in VTM Addenda 72. According to the vendor, the 50 ft-lb torque specification was applicable to the previous rubber gasket and was specified to reduce the thickness of the gasket from 1/16 (.062 ) to .040-.050 . The new gasket was thicker at 1/8 and the 70 Ft.-lbs. was the specified torque. There are two bolts per fitting and are torqued to ensure appropriate compression was applied between the bypass fitting, the gasket, and the exhaust belt. This discrepancy in torque values was identified by the licensee and documented in CR 347658 in September 2009. After discussion with the EDG vendor, the licensee determined that the lower torque value was acceptable given no leakage up to that time had been observed during hydrostatic testing or operation of the diesel; however, the vendor maintained a recommendation of 70 Ft.-lbs. if leakage was observed. In response to the 2H EDG coolant leak on August 23, 2011, the licensee conducted follow-up discussions with the vendor to determine if 50 Ft.-lbs. was acceptable. The vendor restated the recommendation of 70 Ft.-lbs. and performance of a hydrostatic test at 50 psi. The team questioned whether the lower 50 Ft.-lbs. torque value being applied to the new thicker gasket provided the appropriate compression for sealing. A lack of compression can allow the gasket to absorb water and soften, which can lead to gasket extrusion from the flange edge. The licensee was going to perform a technical evaluation to demonstrate adequate compression was available to the gasket. The procedure has since been revised to include the recommended 70 Ft.-lbs. torque specification. Additionally, in September 2009, the licensee documented in CR 347783 that the EDG water bypass fittings had the incorrect surface finish and were not in accordance with the VTM Addenda 72 recommendation of ensuring the exhaust belt had a 125 micro-inch finish and the inlet flange had a 250 micro-inch finish. Though the CR was written to resolve the discrepancy before the next EDG outage (1J), the procedure was not revised until August 2011, following the 2H EDG coolant leak. The team concluded the licensee failed to properly incorporate or evaluate vendor recommendations regarding installation of the cooling water gaskets. At the time of the teams review, the licensee planned to continue evaluating whether the seismic event accelerated the failure of the gasket. Though the licensee eventually inspected all four EDGs following the discovery of the leak on 2H EDG, the team questioned why the licensee initially determined the leak to be an isolated event without having known the cause. The TS requires a common cause evaluation if one EDG is determined to be inoperable. If the cause cannot be confirmed not to exist on the remaining EDGs, the EDGs should be tested to provide reasonable assurance and the corrective action program should continue to evaluate the common cause possibility for the other EDGs. In the case of the 2H EDG leak, the apparent cause was known to be the gasket failure as documented in CR 439091 on August 24, 2011. At the time, the other EDGs were running at full load to support plant shutdown; however, it was not known if the gaskets were installed properly on these EDGs. The CR recognized that previous related issues existed (i.e., multiple coolant leaks across multiple EDGs); however, the licensee still determined the leak was an isolated event. The team observed that this conclusion was based on lack of visible evidence or result (i.e., coolant leakage), but not on a determination of the actual cause. The licensee did submit work orders to inspect the gaskets on the remaining EDGs, but the initial assessment of this being an isolated event did not appear in accordance with proper corrective action program common cause evaluations. The failure of the jacket water cooling gasket caused a leak on the 2H EDG and consequently, inoperability of the 2H EDG during a dual unit LOOP following a seismic event on August 23, 2011. Additional review by the NRC will be needed to determine whether the lack of adequate procedural guidance for EDG cooling water gasket installation represents a performance deficiency. An unresolved item will be opened pending completion of this review. The issue will be identified as unresolved item (URI) 05000338, 339/2011011-02: Failure of 2H Emergency Diesel Generator Jacket Water Cooling Gasket Resulting in Inoperability During Dual Unit LOOP |
| 05000338/FIN-2011011-03 | 2011Q4 | North Anna | Missing Orifice Plate on 1J EDG | Following the seismic event on August 23, 2011, and subsequent failure of the 2H EDG, all four EDGS were subject to thorough inspection and corrective maintenance. On September 3, 2011 during a post-maintenance EDG run, a leak was observed on 1J EDG engine-driven jacket coolant water pump. When the pump was removed for rebuild, it was discovered the pump did not have an orifice plate installed on the discharge of the pump. The orifice plate was subsequently found still attached to the discharge flange of the previously removed pump. An extent of condition was performed and it was observed that the 2J EDG was also missing its orifice plate on the jacket cooling water pump. A missing orifice plate on the jacket cooling water pump discharge flange can cause increased flow and pressure in the jacket cooling system, which in turn can cause 1) operating pressures to reach limitations; (2) degraded cooling capabilities; and (3) potential pipe strain that could lead to leakage or pump and piping fatigue. An installed orifice plate creates a pressure drop and corresponding decrease in flow throughout the system. As flow decreases, the temperature delta must increase to maintain the same amount of heat removal. It was determined the 2J EDG was missing its orifice plate since the last time it was worked on in 2004. A review of past performance data for the 2J EDG (back to 2005) was conducted and it was observed that due to the increased parameters, the temperature delta is lower at full load than normally (4-5 deg. vs. 10-14 delta T normally). Additionally, the 2J engine has required more work input from the engine which lowered the available horsepower to turn the electrical generator; however, past surveillance testing has demonstrated the ability of the 2J EDG to reach rated load. Because the degraded 2J EDG engine driven coolant pump caused some parameter changes on the 2J EDG and could have caused some degradation to the diesel since 2004, additional review by the NRC will be needed to determine whether the missing orifice plate represents a performance deficiency. An unresolved item will be opened pending completion of this review. The issue will be identified as URI 05000338, 339/2011011-03: Missing Orifice Plate on 1J and 2J EDG |
| 05000338/FIN-2011011-06 | 2011Q4 | North Anna | Seismic Alarm Panel | The team reviewed the licensees implementation of the emergency preparedness (EP) procedures used during the event. The review focused on the circumstances surrounding the events to determine if the licensees EP classification and notifications were appropriate and timely. The team interviewed members of the licensees organization and other individuals involved with EP aspects of the event. The team reviewed the event timeline, logs, statements by individuals who responded to the event, the North Anna emergency action level (EAL) matrix, event notification worksheets, and other documents related to EP classifications. b. Observations and Findings. The team concluded that emergency planning declarations were appropriate. The team identified one URI described in this section. In order to determine the appropriateness of the EP classifications, the team performed a detailed assessment of the event timeline with particular attention to those activities that are entry points for the EAL matrix. On August 23, 2011, at 1:51 p.m., the site experienced a magnitude 5.8 earthquake with an epicenter twelve miles southwest of the plant. Both reactors tripped. A LOOP occurred at 1:51:12 p.m. All four EDGs auto started to their respective emergency bus (1H, 1J, 2H, and 2J) at 1:51:20 p.m. An Alert was declared at 2:03 p.m. for HA6.1, SM judgment, due to an inability to enter the seismic EAL for seismic event because the seismic monitoring panel earthquake trouble alarm to notify operators of a seismic event did not illuminate. HA1.1, earthquake response, required that the strong motion accelerograph peak shock annunciator illuminates, which would indicate a seismic event greater than OBE (0.06g horizontal or 0.04g vertical) and an earthquake confirmed by any of the following: FnEarthquake felt in plant FnNational Earthquake Information Center (NEIC) FnControl Room indication of degraded performance of any safety-related structure, system, or component The strong motion accelerograph peak shock annunciator did not illuminate. The seismic monitoring panel has two recording systems, one provided by Kinemetrics Inc. and the other provided by Engdahl. Both systems provide input to the main control room via a common instrumentation panel on the Unit 2 side of the control room. All sensors for the Kinemetrics system are located inside Unit 1 containment. The Kinemetrics system has a seismic trigger, which activates at 0.01g in a any direction. In addition, there is a seismic switch which activates at 0.04g vertical and 0.06 horizontal. Neither the seismic switch nor the seismic trigger activated the earthquake trouble alarm. Locally at the seismic panel, the seismic trigger was activated and a tape recording of the event was recorded. Therefore, operators determined that the seismic monitoring panel was inoperable for making a decision about the strength of the earthquake. The team determined that the lack of control panel alarm from the seismic monitoring panel did not delay an Alert declaration, because the SM used HA6.1, SM judgment. Because of the issues identified with the seismic monitoring panel and because it is used as an input for EAL decisions, additional review by the NRC will be needed to determine whether this issue represents a performance deficiency. An unresolved item will be opened pending completion of this review. The issue will be identified as URI 05000338, 339/2011011-06: Seismic Alarm Panel. Personnel in the plant monitoring the 2H EDG reported the coolant leak to the control room via face-to-face communication. Operators tripped the 2H EDG at 2:40 p.m. An Alert was declared at 2:55 p.m. for SA1.1, AC power, for Unit 2, because the AC capability was reduced to a single source with 2J EDG. The team determined that notifications to the State and Counties and to the NRC Operations Center were timely and accurate. The Alert event was downgraded to a Notice of Unusual Event (NOUE) at 11:16 a.m. on August 24, for HU1.1, seismic activity, due to the potential for aftershocks. The NOUE was exited on August 24, 2011, at 1:15 p.m. The decision to terminate the event was based on the following: (1) no public issues existed that would necessitate the continued activation of the State and County Emergency Operations Facilities; (2) the licensees Outage Control Center had established a technical focus and was aligned for the recovery activities; and (3) no additional aftershocks were received at the plant. The team determined that downgrade of the Alert event at 11:16 a.m. was appropriate. |
| 05000338/FIN-2011011-07 | 2011Q4 | North Anna | Safety Related Instrumentation Anomalies | During the post event review, the licensee identified some unexpected anomalies that occurred during the event, related to safety related instrumentation. The team independently reviewed event recorders, plant records, and interviewed personnel to determine whether the licensee had identified and appropriately addressed any observed equipment performance issues. The team found that some plant instrumentation anomalies warranted follow-up. The team identified one URI described in this section. The licensee had identified and recorded a number of instrument anomalies, many of which were attributed to the earthquake. Some examples of instruments affected included: Minor perturbations in Units 1 and 2 Safety Injection Accumulator and Refueling Water Storage Tank (RWST) levels Nuclear Instrumentation Loop 1C High Delta Temperature Hi-Hi Steam Generator Level RWST Chemical Addition Tank Temperature The team questioned whether these anomalies were indications of actual parameter changes in level, pressure, etc. due to the seismic event or false indications that were seismically induced. If the indications were seismically induced, the team inquired whether the instrument exceeded their seismic qualification or whether the seismic qualification of the instrument was appropriate. The licensee planned to determine the most likely cause of the anomalies through their root cause assessment of the August 23, 2011 seismic event. Because some of the anomalies identified with the safety related instrumentation could have been seismically induced and thus potentially calls into question the seismic qualification of the instruments, additional review by the NRC will be needed to determine whether this issue represented a performance deficiency. An unresolved item will be opened pending completion of this review. The issue will be identified as URI 05000338, 339/2011011-07: Safety Related Instrumentation Anomalies. |
| 05000338/FIN-2011004-01 | 2011Q3 | North Anna | Failure to Take Adequate Corrective Action to Preclude a Fire in the Units 1 and 2 Control Room Complex | A self-revealing finding was identified for the failure to take adequate corrective action for degradation of annunciator card resistors in accordance with the standards as established by the licensees corrective action program procedure which resulted in a fire in the respective annunciator cabinet located in the Units 1 and 2 control room complex. The licensee entered the problem into their corrective action program as condition report 412487. The finding was more than minor because it could be reasonably viewed as a precursor to a significant event based on fire development leading to an evacuation of the control room. The finding was screened using phase 1 of the SDP and was determined to be a fire initiator contributor within the initiating events cornerstone and required a phase 3 fire SDP risk assessment in as it represented a fire within the main control room (MCR). A regional SRA performed an SDP phase 3 fire risk assessment for this finding in accordance with NRC Inspection Manual Chapter (IMC) 0609 Appendix F, NUREG/CR 6850 and NUREG/CR 6850 supplement 1. . The SDP phase 3 risk evaluation determined that the risk of the finding was an increase in core damage frequency of <1E-6/year, a Green finding of very low safety significance. The inspectors determined there were no cross-cutting aspects because the performance deficiency was not representative of current licensee performance. |
| 05000338/FIN-2011004-02 | 2011Q3 | North Anna | Licensee-Identified Violation | 10 CFR 50, Appendix B, Criterion XVI, requires the licensee to identify and correct conditions adverse to quality involving the unacceptable presence of Microtherm and Cal-Sil insulation within the GSI 191 zone of influence (ZOIs) inside each Units containment. Contrary to this above, on September 22, 2010, the licensee identified that an inadequate methodology was used to determine the types and quantities of insulation during the GSI-191 containment walkdowns in 2003 and 2004, resulting in unacceptable insulation not being included in the containment debris inventory and subsequently removed. The issue is more than minor because it associated with the Mitigating Systems cornerstone and the related attribute of equipment availability and reliability because the presence of Microtherm and Cal-Sil insulation within the ZOI would impact the availability and reliability of the containment sump strainers in post-loss of coolant accident (LOCA)/high energy line break (HELB) conditions. A phase 1 Significance Determination Process (SDP) screening determined that the finding represented a potential loss of long term decay heat removal as the Microtherm could impact flow from both the Low Pressure Safety Injection (LHSI) containment sump strainer and the Recirculation Spray (RS) sump strainer during the recirculation phase of a LOCA. The phase 2 SDP evaluation determined that the finding was potentially greater than Green but did not account for the specific LOCA size and frequency required to release the insulation, the probability factor of the LOCA occurring at locations where the insulation was present, or the potential recovery actions, therefore a detailed phase 3 SDP risk assessment was performed by a regional Senior Reactor Analyst (SRA). The risk was mitigated by the low probability of the required initiators and the proceduralized recovery actions. The result of the phase 3 SDP evaluation was a core damage frequency increase for the PD of <1E-6 per year, a Green finding of very low safety significance. The licensee has documented in their corrective action program as CR 396377. |
| 05000338/FIN-2011003-05 | 2011Q2 | North Anna | Failure to Take Adequate Corrective Action to Preclude a Fire in the Units 1 and 2 Control Room Complex | A self-revealing finding was identified for the failure to take adequate corrective action for degradation of annunciator card resistors in accordance with the standards as established by the licensees corrective action program procedure which resulted in a fire in the respective annunciator cabinet located in the Units 1 and control room complex. The licensee entered the problem into their corrective action program as condition report 412487. The finding was more than minor because it could be reasonably viewed as a precursor to a significant event based on fire development leading to an evacuation of the control room. In accordance with NRC IMC 0609, Significant determination Process, and the associated Appendix F, the inspectors performed a phase 1 analysis and determined the finding would require a Phase 2 analysis be a regional senior reactor analyst because the fire impacts the control room. Consequently, the significance of this finding is TBD pending completion of the significance evaluation. The cause of this finding incolved the cross-cutting area of problem identification and resolution, the component of the corrective action program, and the aspect of appropriate and timely corrective action, P.1 (D), because the licensees corrective action plan, in spite of additional failures involving fire precursors, was not timely to preclude a fire event. |
| 05000338/FIN-2010006-01 | 2010Q4 | North Anna | Failure to Remove Particulate Insulation to Meet Strainer Performance Requirements | In August 2006, Atomic Energy Canada Limited (AECL) performed testing of potential containment debris loading. Cal-Sil and Microtherm insulation produced debris-induced head losses above the allowable values for the planned design for the RS and LHSI containment sump strainers. VEPCO implemented DC 07-004 in the spring, 2007 to remove Cal-Sil and Microtherm insulation from Unit 2 and also implemented DC 05-014 to install the modified containment sump strainers. VEPCO implemented DC 07-129 in fall 2007 to remove undesired insulation from Unit 1, and DC 05-013 to install modified containment sump strainers. On February 29, 2008, VEPCO submitted a supplemental response for North Anna Units 1 and 2 for NRC GL 2004-02. The submittal included a list of corrective actions including the removal of all Microtherm insulation from Unit 2. Unit 1 was identified as having no Microtherm insulation inside containment. In November 2008 VEPCO implemented and completed field changes to DC 05-013 (Unit 1) and DC 05-014 (Unit 2) to update the North Anna licensing basis to meet the requirements of with GL 2004-02 (except for in-vessel effects). The NRC reviewed and accepted VEPCOs response to GL 2004-02 with the exception of in-vessel effects in a letter dated May 28, 2009. The team did not identify an immediate safety concern for this issue of concern because both units were shutdown at the time of this inspection activity. The team monitored licensee activities during the inspection weeks and noted these activities were focused on the removal of all the Microtherm insulation identified in both units. The team determined that the licensee has performed a reasonable search to identify Cal-Sil and Microtherm insulation inside containment and has either removed the insulation or properly analyzed leaving it in containment. The team determined additional inspection was required to determine if a performance deficiency existed. In order to properly disposition this issue of concern, additional inspection would be required to better understand: 1) the licensees formal cause determinations for how both Cal-Sil and Microtherm insulation in both units was originally missed; 2) planned licensee corrective actions to address any potential programmatic issues identified in the formal cause determinations; 3) NRC reliance on correspondence between NRC and VEPCO related to GL-2004-02; and 4) NRC understanding of the licensees design as documented in the current Safety Evaluation Report for North Anna Units 1 and 2. This issue of concern was identified as URI 05000338/339/2010006-01, Failure to Remove Particulate Insulation to Meet Strainer Performance Requirements. |
| 05000338/FIN-2010005-01 | 2010Q4 | North Anna | Appendix R Fire Protection for RCS Instrumentation in Containment | The licensee initiated CR396368 and CR397441 for Units 1 and 2 respectively to document resident inspector concerns regarding radiant heat shields used for Appendix R fire protection features associated with reactor coolant system (RCS) pressurizer level and pressure transmitters and respective cabling located within containment. The concerns were related to adequate protection from an exposure fire which can involve either in situ or transient combustibles. The inspectors require additional information from the licensee to determine if there is a performance deficiency which is greater that minor. This issue is identified as URI 05000338, 339/2010005-01, Appendix R Fire Protection for RCS Instrumentation in Containment. |
| 05000338/FIN-2009004-01 | 2009Q3 | North Anna | Control of Transient Combustibles | An unresolved item (URI) was identified by the inspectors relating to compliance with the licensees procedures, VPAP-2401, Fire Protection Program, Revision 29, which was superseded by CM-AA-FPA-100, Revision 0, Fire Protection/Appendix R (Fire Safe Shutdown) Program, on August 14, 2009, with their fire protection program license requirement relative to Appendix A to Branch Technical Position APCSB 9.5-1.On July 27, 2009, the licensee initiated condition report (CR) 342754 for a NRC-identified failure to obtain a transient fire loading permit for transient combustibles pre-staged in the Unit 2 safeguards building. The inspectors review of the licensees fire protection program required by North Anna Power Plant Facility Renewed Operating Licensee NPF-4 & 7, Condition D, and described in USFAR section 9.5.1, Fire Protection System, identified issues relating to Appendix A to Branch Technical Position APCSB 9.5-1 and the licensees compliance as implemented by their fire protection program procedures noted above. Specifically, the inspectors identified changes in the methodology of transient combustible controls from VPAP-2401, Revision 0, up to Revision 29 which was in effect on July 27, 2009.The issues are unresolved pending completion of NRC review of additional licensee documents to determine if there are performance deficiencies relating to fire protection program changes and implementation which are greater than minor and are identified as URI 05000338, 339/2009004-01, Control of Transient Combustibles. |