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At approximately 1934 EDT on May 15, 2013, maintenance personnel entered the primary containment personnel air lock to determine the cause of the inability to attain test pressure during a type B leak rate of the airlock. The inner door seal was found degraded and partially rolled from its required position allowing air from inside the airlock to enter the primary containment. During the limited time the outer airlock door was opened for access into the airlock concurrent with the degraded seal on the inner door, a condition existed that could have prevented the fulfillment of the safety function of the structure to control the release of radioactive material. The inner door seal was subsequently replaced and the leak rate of the personnel air lock completed with satisfactory results. During the seal replacement activity, the outer airlock door remained closed to provide the barrier against the release of radioactive material should it be required. This is a notification per 10 CFR 50.72(b)(3)(v) for a condition that could have prevented the control of the release of radioactive material. It is recognized that this notification (was) not within eight hours of the event. The condition has been entered into the station's corrective action program. The licensee will notify the New York State Public Service Commission and the NRC Resident Inspector.

• * * RETRACTION ON 6/27/13 AT 1549 EDT FROM KROCK TO HUFFMAN * * *

This notification is being made to retract Event Notification #49043, which reported a condition that could have prevented the control of the release of radioactive material when the primary containment airlock inner door seal was found degraded concurrent with the outer door being open. Further analysis by engineering of the actual conditions which were recorded when the airlock Type B leak rate test was being performed and calibration checks of the leak rate monitor instrumentation used for the test, has determined that the leakage through the degraded inner airlock door seal, when combined with the Appendix J As-Left Minimum Pathway Type B and C leak rates, remains below the Technical Specification Primary Containment As-Left Minimum Pathway Leakage Limit of 0.6 La. Therefore, for the period in which the inner airlock door seal was degraded and the outer airlock door was open, the primary containment function to control the release of radioactive material was maintained and the initial notification per 10 CFR 50.72(b)(3)(v) is being retracted. The licensee has notified the NRC Resident Inspector and the New York State Public Service Commission. R1DO (Ferdas) notified.

This notification is being made in accordance with 10 CFR 50.72(b)(3)(ii) which states in part Any event or condition that results in (A) the condition of the nuclear power plant, including its principle safety barriers, being seriously degraded; or (B) the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety and 10 CFR 50.72(b)(3)(v) which states in part Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (A) Shut down the reactor and maintain it in a safe shutdown condition; (B) Remove residual heat; (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident. This notification describes a licensee identification of a condition where the low pressure emergency core cooling systems (ECCS) may not have been able to perform their safety functions of removing residual heat and significantly degrades plant safety. The condition has been corrected. At 2152 on 15 February 2008, while operating at 100% power, Nine Mile Point Unit 2 completed evaluating a 10 CFR 21 communication from General Electric on ECCS suction strainers, and concluded that the calculation on debris head loss was non conservative. The original design basis net positive suction head calculations assumed a suppression pool water level of 199.5 feet. Based upon the General Electric notification, at this suppression pool water level, the low pressure core spray and all three residual heat removal systems might not have been able to perform their safety functions. Further engineering evaluation determined that if the suppression pool level was (greater than or equal to) 200.3 feet then the suction strainers debris head loss could be met and the low pressure ECCS would be able to perform their safety functions. At 1902 the control room operators took action to raise suppression pool water level while engineering completed their evaluation based on the expectation that suppression pool water would have to be raised. At 1910 on 15 February 2008, suppression pool water level was raised to 200.3 feet, which resulted in the low pressure core spray and residual heat removal systems being able to perform their safety function. The licensee will notify the NRC Resident Inspector.

• * * RETRACTION ON 4/12/08 AT 1001 EDT FROM PETRELLI TO HUFFMAN * * *

After further review, this event notification report is being retracted based on the following: The notification was initiated due to a 10 CFR 21 communication from General Electric on ECCS suction strainers, indicating that the calculation of suction strainer head loss was non-conservative. As a result, at the assumed suppression pool water level of 199.5 feet, adequate net positive suction head may not be available for the low-pressure ECCS pumps. Suppression pool water level was raised 9.8 inches, to 200.3 feet, which provided assurance that the low pressure ECCS pumps were capable of performing their specified safety functions. Further evaluation by plant staff has determined that there are margins available in the suction strainer head loss calculations and in the design basis ECCS pump net positive suction head calculations that, when combined, exceed the increase in suction strainer debris head loss identified in the General Electric communication. Based on these available margins, there was adequate net positive suction head for the low pressure ECCS pumps at the originally assumed suppression pool water level of 199.5 feet. In addition, the as-found quantity of corrosion products and debris removed from the suppression pool during the current refueling outage was significantly less than the quantity assumed in the design basis suction strainer head loss calculations, indicating that additional analytical margin existed. Thus, the low pressure ECCS pumps were operable and capable of performing their specified safety functions without reliance on the 9.8 inches of water level added to the Suppression pool. Raising the suppression pool water level was a conservative action but was not necessary to maintain operability of the low pressure ECCS pumps. Therefore, this event is not reportable under either 10 CFR 50.72(b)(3)(ii) or 10 CFR 50.72(b)(3)(v). The licensee notified the NRC Resident Inspector. R1DO (Conte) notified.

This notification is being made in accordance with License Condition 2.F for Nine Mile Point Unit 2 which states in part 'report any violations of the requirements contained in Section 2.C of this license in the following manner: initial notification shall be made within 24 hours to the NRC Operations Center via the Emergency Notification System, with written follow-up within 30 days in accordance with the procedures described in 10 CFR 50.73(b), ( c), and (e).' License Condition 2.C (2) states in part 'Nine Mile Point Nuclear Station, LLC shall operate the facility in accordance with the Technical Specifications.' This notification describes a licensee identified condition where both redundant Standby Gas Treatment (SGT) trains were apparently inoperable in violation of Technical Specifications. The condition has been corrected. At 1800 on 3 March 2006, while operating at 91 % power (coast down to refueling), Nine Mile Point Unit 2 identified a condition in which both trains of SGT were apparently rendered inoperable for intermittent time periods of a few hours in length, starting from 17 February 2006 through about 1900 on 28 February 2006. This was not recognized at the time; as such the requirement to initiate a plant shutdown per LCO 3.0.3 was not performed. The condition was caused by use of a heavy-duty tarp and associated cargo net supporting it from underneath, installed across the Unit 2 Reactor Building Hoist Well. Installation of the tarp and net across the hoist well occurred between the above dates, for time periods of a few hours each, in order to support refueling preparations, thereby avoiding spread of contamination during rigging activities. The blockage of the Reactor Building Hoist Well would have obstructed or significantly degraded the design flow paths of both trains of SGT if called upon to perform their safety functions in a design basis accident. Therefore current information indicates this tarp installation configuration renders the SGT system inoperable. The tarp and net were permanently removed at about 1900 on 28 February 2006 when a supervisor questioned if tarp installation was allowed while the reactor was at power. Although removal of the tarp and net typically required only a few minutes effort by plant workers, its installation and continued blockage of the ventilation flow path would have resulted in declaration of the (SGT) safety systems to be inoperable if not removed. Workers were not sensitive to the safety function of the open ventilation flow path provided by the hoist well, and no programmatic training or administrative requirements were identified which prohibited the configuration at conditions other than cold shutdown. Nine Mile Point is in the process of taking compensatory measures to preclude installation of the tarp when SGT is required to be operable by briefing operations, radiation protection and refuel worker crews on ventilation requirements and sensitivity to safety functions. Operations took physical control (lock and key) of the tarp. Corrective actions to provide administrative controls on the tarp installation are in process. Detailed evaluation of the safety significance of the condition is ongoing. Initial review of plant records indicate that this configuration was also installed intermittently around July 2003. It was recognized as undesirable but was not identified as an operability or reportability issue at the time. Corrective action to prevent its recurrence was not effective. More detailed information on specific dates and durations when this configuration existed will be provided in the 30 day written LER report, after a detailed review.

The instances noted above and any similar conditions identified will be explained in detail in the follow-up LER that will be submitted as required by 10CFR 50.73(a)(2)(i)(B) - 'Any operation or condition which was prohibited by the plants Technical Specifications .'" Unit-1 is not affected since they have a different method to control use of this tarp. The licensee notified the NRC Resident Inspector.

• * * RETRACTION FROM T. RESTUCCIO TO HUFFMAN AT 2209 ON 3/28/06 * * *

At 1800 on 3 March 2006, while operating at 91% power (coast down to refueling), Nine Mile Point Unit 2 identified a condition in which both trains of the Standby Gas Treatment (SGT) system were apparently inoperable for intermittent time periods of a few hours of length, starting from 17 February 2006 through about 1900 on 28 February 2006. This was not recognized at the time; as such the requirement to initiate a plant shutdown per LCO 3.0.3 was not performed. The condition was caused by use of a heavy-duty tarp and associated cargo net supporting it from underneath, installed across the Unit 2 reactor Building Hoist Well. Installation of the tarp and net across the hoist well occurred between the above dates, for time periods of a few hours each, in order to support refueling preparations, thereby avoiding the spread of contamination during rigging activities. The blockage of the reactor Building Hoist Well would have obstructed or significantly degraded the design flow paths of both trains of SGT if called upon to perform their safety functions in a design basis accident. Review of plant records indicate that this condition was also installed intermittently around July 2003. A subsequent evaluation of the safety significance of this condition has been performed. This evaluation considered actual area of flow path remaining with the tarp in place, as well as bounding outside temperatures during the times the tarp may have been installed. The evaluation has concluded that the secondary containment function, and therefore the SGT system, remained operable and would have performed its intended safety function during a design basis accident during the time periods the tarp may have been installed during the last three years. This evaluation provides the basis for retraction of the ENS report of March 4, 2006. The licensee notified the NRC Resident Inspector. The R1DO(Cook) has been notified.