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On 09/21/2017 at 1550, Operations started Control Room Emergency Ventilation (CREV) Air Conditioning (AC) for Tracer Gas Testing. Per Operations instructions, Mechanical Maintenance went to inspect the Control Room Emergency Ventilation system for refrigerant leaks before Tracer Gas Testing was started. Mechanical Maintenance reported a refrigerant leak on the discharge piping of the compressor, right above the inlet to the condenser. The leak was at the expansion joint of a fitting. The safety significance of this event was minimal.

The cause of the refrigerant leak on the Control Room Emergency Ventilation compressor discharge pipe fitting into the condenser was due to high cycle fatigue.

The corrective action was to replace the failed Control Room Emergency Ventilation compressor discharge pipe fitting.

The CREV AC system is a single train system. Given the impact on the CREV AC system, this report is submitted in accordance with the requirements of 10 CFR 50.73(a)(2)(v)(D), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

On March 27, 2017, during refueling outage Q1R24 at 0840 hours, the Unit 1 Main Steam Isolation Valve (MSIV) as-found closure time test results indicated that four MSIVs failed to close within the required Technical Specification (TS) time of less than or equal to five seconds. The safety significance of this event was minimal.

The cause of three of the slow closure timing events was due to a less than optimal replacement frequency for the MSIV actuators, and the cause of the fourth slow closure timing event was due to a less than optimal replacement frequency for the MSIV springs.

Corrective actions included replacing the 1-0203-1B and 1-0203-1D MSIV actuators, replacing the springs on the 1-0203-2C MSIV, readjusting the as-left closure times on all four MSIVs and satisfactory retesting prior to startup. Follow-up corrective actions include replacing the 1-0203-2D MSIV actuator and changing the preventive maintenance frequency and description.

Since the MSIV slow closure times were due to degradation from less than optimal replacement frequencies, it is likely the degradation occurred over time since the last successful refueling outage testing and during power operations when the required TS 3.6.1.3, Primary Containment Isolation Valves was applicable. Therefore, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B), which requires reporting of any operation or condition that was prohibited by the plant's TS.

result, the Station determined that a drywell entry was required to investigate the condition, make any needed repairs, and refill the oil reservoir. NRC provided that Station personnel did not comply with Technical Specifications (TS) 3.6.2.5 (DW to Suppression.

Chamber DP) and 3.6.3.1 (Primary Containment 02 concentration) since while in MODE 1, at the end of the 32 hour Completion Time (24 hour Action A, plus the 8 hour Action B) during the actual plant evolutions for power ascension, these Required Actions were not met because the associated Applicability for each TS were not met since the Unit remained in MODE 1.

The cause of the issue was Station personnel understanding and application of the subject TS as used in context under this infrequent plant condition, differed from the NRC's understanding and application of the subject TS. The specific difference is with the application of the term, "start-up," as used in the LCO Applicability.

Corrective actions included issuance of an Operations Standing Order, and revision of pertinent Operating procedures to ensure these Tech Specs are properly implemented.

The safety significance of this event was minimal. Given the impact on the Drywell/Suppression Chamber Differential Pressure, and Primary Containment Oxygen Concentration Technical Specifications, this report is submitted for Unit 2 in accordance with the requirements of 10 CFR 50.73(a)(2)(i)(B), which requires the reporting of a past operation or condition which was prohibited by the plant Technical Specifications.

PLANT AND SYSTEM IDENTIFICATION

General Electric - Boiling Water Reactor, 2957 Megawatts Thermal Rated Core Power Energy Industry Identification System (EIIS) codes are identified in the text as (XX).

EVENT IDENTIFICATION

Compliance Issue with the Drywell/Suppression Chamber Differential Pressure, and Primary Containment Oxygen Concentration Technical Specifications

A. CONDITION PRIOR TO EVENT

Unit: 2 Reactor Mode: 1 Event Date: May 25, 2016 Event Time: 11:10 hours Mode Name: Power Operation Power Level: 100%

B. DESCRIPTION OF EVENT

On 05/23/16 Low Level Alarm (LA) 2A Recirc (AD) Motor (MO) occurred due to a low oil level condition for the 2A recirculation pump (P) motor. As a result, the Station determined that a drywell (NH) entry was required to investigate the condition, make any needed repairs, and refill the oil reservoir (TK). NRC provided that Station personnel did not comply with TS 3.6.2.5 (DW to Suppression Chamber DP) and 3.6.3.1 (Primary Containment 02 concentration (BB)) since while in MODE 1, at the end of the 32 hour Completion Time (24 hour Action A, plus the 8 hour Action B) during the actual plant evolutions for power ascension, the Required Actions B for TS 3.6.2.5 and TS 3.6.3.1 were not met (at 1110 on 5/25/16, and 1123 on 5/25/16, respectively), because the Unit 2 LCO Applicability for establishing DW/Torus differential pressure and being fully inerted were not met since the Unit remained in MODE 1.

NRC provided that these TS were not met when the Station improperly used the LCO Applicability (a), 24 hour "clock reset" allowance to proceed above 15% power "following startup" without setting the DW/Torus differential pressure (Dp) > 1 psid, and oxygen concentration contrary to the NRC's "plain language" interpretation of this associated TS Applicability, in that "following startup" was intended to mean "following MODE 2." Furthermore, the NRC provided that the Unit did not exit the Mode of Applicability just by dropping below 15% Rated Thermal Power (RTP), since the Unit was still in MODE 1, and a total of only 32 hours was available to re-achieve DW/Torus Dp and reinert while remaining in MODE 1. While under this interpretation, the resulting available options during this drywell entry were to either: 1) re-establish DW/Torus Dp and inerting prior to reaching 15% RTP during the power ascension, or 2) to exit MODE 1 to reset the 24 hour clock (meaning to start power ascension from MODE 2). In this situation, the TS LCO Applicability is not clear, does not coincide with the Bases intent, and may be overly restrictive in that it uses the terms, "startup" and "shutdown.

The cause of the issue was Station personnel understanding and application of the subject TS as used in context under this this infrequent plant condition, differed from the NRC's understanding and application of the subject TS.

The specific difference is with the application of the term, "start-up," as used in the LCO Applicability.

The safety significance of this event was minimal. Given the impact on compliance with the Drywell/Suppression Chamber Differential Pressure, and Primary Containment Oxygen Concentration Technical Specifications, this report is submitted for Unit 2 in accordance with the requirements of 10 CFR 50.73(a)(2)(i)(B), which requires the reporting of a past operation or condition which was prohibited by the plant Technical Specifications.

C. CAUSE OF EVENT

During the drywell entry and subsequent return to full power, the Station performed the power ascension under procedures, QCGP 3-1 (Reactor Power Operations) and QCOP 1600-20 (Nitrogen Inerting of Primary Containment Using the Vaporizer(s) and Reactor Building Ventilation System), for which under this infrequent plant condition, the context of "startup" was understood to refer to the "act of increasing reactor power," or "power ascension." Therefore, the apparent TS interpretation conflict occurred in the meaning and use of "startup," in the LCO Applicability, when during power ascension the Station proceeded above 15% RTP without resetting DW/Torus Dp and re-inerting within the 32 hour maximum allowed Completion Time.

This issue pertained to a reading of the language of the subject TS which in itself was not readily able to be consistently interpreted since the "plain language" did not match the TS Bases nor the NRC approved text of the Safety Evaluation (SE). This TS compliance interpretation issue occurred for only a 4 hour and 2 hour duration (in excess of the 32 hours total Completion Time allowed while in MODE 1), pertaining to the DW/Torus Dp and oxygen concentration, respectively.

D. SAFETY ANALYSIS

System Design TS Bases 3.6.2.5, Drywell-to-Suppression Chamber Differential Pressure Applicable Safety Analyses provides: "The purpose of maintaining the drywell at a slightly higher pressure with respect to the suppression chamber is to minimize the drywell pressure increase necessary to clear the downcomer pipes to commence condensation of steam in the suppression pool and to minimize the mass of the accelerated water leg. This reduces the hydrodynamic loads on the torus during the LOCA blowdown. The required differential pressure results in a downcomer waterleg of approximately 1 ft. Initial drywell-to-suppression chamber differential pressure affects both the dynamic pool loads on the suppression chamber and the peak drywell pressure during downcomer pipe clearing during a Design Basis Accident LOCA. Drywell-to suppression chamber differential pressure must be maintained within the specified limits so that the safety analysis remains valid.

TS Bases 3.6.3.1, Primary Containment Oxygen Concentration Applicable Safety Analyses provides: "The UFSAR, Section 6.2.5 calculations assume that the primary containment is inerted when a Design Basis Accident loss of coolant accident occurs. Thus, the hydrogen assumed to be released to the primary containment as a result of metal water reaction in the reactor core will not produce combustible gas mixtures in the primary containment. Oxygen, which is subsequently generated by radiolytic decomposition of water, will not result in the primary containment becoming de-inerted within the first 30 days following an accident.

Safety Impact TS Bases 3.6.2.5 Drywell-to-Suppression Chamber Differential Pressure LCO Applicability provides: "As long as reactor power is containment occurring within the first 24 hours following a startup or within the last 24 hours prior to a shutdown is low enough that these "windows," with the primary containment not inerted, are also justified. The 24 hour time period is a reasonable amount of time to allow plant personnel to perform inerting or de-inerting." For this event, since the period of time during which reactor power was > 15% RTP while the DW to Torus Dp was 18 hours, the probability of an event that generates hydrogen or excessive loads on primary containment was low since this duration was less than 24 hours, therefore, the safety impact of this condition was minimal.

TS Bases 3.6.3.1, Primary Containment Oxygen Concentration LCO Applicability provides: "As long as reactor power is containment need not be inert. Furthermore, the probability of an event that generates hydrogen occurring within the first 24 hours of a startup, or within the last 24 hours before a shutdown, is low enough that these "windows," when the primary containment is not inerted, are also justified. The 24 hour time period is a reasonable amount of time to allow plant personnel to perform inerting or de-inerting." For this event, since the period of time during which reactor power was > 15% RTP while the DW was not inerted (i.e., 02 concentration > 4%), was approximately 16 hours, the probability of an event that generates hydrogen was low since this duration was less than 24 hours, therefore, the safety impact of this condition was minimal.

Due to the language in the associated TS Bases and SE documentation for the actions that the Station took during the drywell entry and subsequent power ascension, this TS compliance interpretation issue is not a significant event/issue, since the interpreted non-compliance occurred for only a 4 hour and 2 hour duration, pertaining to the DW/Torus Dp and oxygen concentration, respectively (i.e., 4 hour/2 hour in excess of the 32 'hours total Completion Time allowed while in MODE 1). Furthermore, this event was the first known recorded occurrence of non-compliance with these TS under this interpretation. Since the condition created no consequences, the safety impact of this condition was minimal.

Risk Insights The plant Probabilistic Risk Assessment (PRA) model was reviewed with respect to this event. Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) were evaluated for impacts of oxygen concentration and DW/Torus Dp. Since the period of time during which reactor power was > 15% RTP while the DW was not inerted (i.e., oxygen concentration > 4%), was approximately 16 hours, and since the period of time during which reactor power was > 15% RTP while the DW to Torus Dp was change in risk was minimal.

In conclusion, the overall safety significance and impact on risk of this event were minimal.

E. CORRECTIVE ACTIONS

Immediate:

1. Issued an Operations Standing Order that provided clarifying information when using the subject Tech Spec for drywell entries.

Follow-up:

2. The pertinent Operating procedures will be revised to ensure the subject Tech Specs are properly implemented for drywell entries.

3. This issue will be addressed under a proposed BWROG TSTF item for a potential future Tech Spec and Bases revision.

4. Operator Training will review this issue as an OPEX item, and for incorporation into appropriate lesson plans.

F. PREVIOUS OCCURRENCES

The Station events database, LERs, and INPO Consolidated Event System (ICES) were reviewed for similar events at the Quad Cities Nuclear Power Station. This event was caused by Station personnel understanding and application of the subject Tech Specs as used in context under this infrequent plant condition, differed from the NRC understanding and application of the subject Tech Specs. The specific difference is with the application of the term, "start-up," as used in the LCO Applicability.

• No previous occurrences were identified as applicable to the circumstances of this event.

G. COMPONENT FAILURE DATA

Failed Equipment: N/A Component Manufacturer: N/A Component Model Number: N/A Component Part Number: N/A This event has not been reported to ICES since there was no equipment failure.

On March 21, 2016, at 2200 hours, with Unit 2 shutdown for refuel outage Q2R23, the as-found local leak rate tests (LLRT) for the four (4) main steam lines (MSL) were performed following closure of the main steam isolation valves (MSIV). The initial as-found LLRT on the "A" and "C" MSL MSIVs exceeded the minimum pathway criteria (lesser leakage in a line) of the Technical Specifications (TS), and the combined total leakage of all MSLs also exceeded the minimum pathway criteria (lesser leakage in each line when combined for all MSIVs) of the TS.

Corrective actions included flushing, disassembling, inspecting, repairing, and retesting the valves. Future corrective actions include installation of an improved spherical nose plug design to the MSIV plug and seat, and installation of an anti-rotation device to the MSIV pilot.

Valves 2-0203-2A and 2-0203-1C were disassembled and inspected. The most likely cause for the higher than expected leakages has been determined to be a valve design that is susceptible to a degraded main plug / seat interface during valve closure. A contributing cause was susceptible pilot plug / seat misalignment, due to pilot disc stem nut wear.

The safety significance of this event was minimal. The total primary containment leakage of 315.866 scfh was well within the allowed leakage limit of 1372.99 scfh (La). However, since the "A", "B", "C" and "D" MSL MSIV as-found leakage exceeded the TS limit, and the combined total leakage of all MSLs exceeded the TS limit, this report is submitted in accordance with the requirements of 10 CFR 50.73(a)(2)(i)(B), which requires the reporting of a past operation or condition which was prohibited by the plant Technical Specifications.

building. The alarms occurred during an entry to the Unit 2 Reactor Water Cleanup (RWCU) Heat Exchanger (HX) room. A negative reactor building pressure was restored within one minute (alarm cleared at 13:41 hours) by immediately securing a reactor building supply fan. Since both Units 1 and 2 share a common reactor building (RB), the loss of differential pressure (RB pressure went positive) for approximately one (1) minute impacted both Units 1 and 2 secondary containments.

The cause was a sheared air line inside the Unit 1 RB ventilation exhaust plenum which depressurized the air header supplying operating air to all three Unit 1 reactor building exhaust fan isolation dampers and causing the dampers to fail open, including the one on the standby fan.

Corrective actions included replacing the sheared air line, and the addition of a preventive maintenance task for replacement of equivalent air lines on all RB supply and exhaust fan dampers.

The safety significance of this event was minimal. Given the impact on the secondary containment, this report is submitted (for Units 1 and 2) in accordance with the requirements of 10CFR 50.73(a)(2)(v)(C), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

Emergency Ventilation (CREV) System, technicians noticed that the 'B' Air Filtration Unit (AFU) Booster Fan discharge damper became stuck in a partially open position following the 'B' AFU Booster Fan trip on a high ammonia input signal. Due to the uncertainty of being able to achieve rated airflow for the CREV System caused by recirculation that would result from running the 'A' AFU Booster Fan with the 'B' Booster Fan discharge damper partially stuck open, the CREV System was declared inoperable and surveillance testing was secured. As a result, Technical Specification 3.7.4, Condition A, was entered.

The cause of the damper failure was due to inadequate clearance between the damper seat sealing area and the damper blade to shaft fasteners which resulted in misalignment which caused the damper shaft to bend and the damper to become stuck.

Corrective actions included securing the stuck damper in the closed position and evaluating all CREV System dampers. A preventative maintenance task will be developed to stroke and inspect the dampers to identify binding; modifications will be made if necessary to other CREV System dampers to prevent binding.

The safety significance of this event was minimal. Given the impact on the CREV System, which is common to both Units, this report is submitted (for Units 1 and 2) in accordance with the requirements of 10 CFR 50.73 (a)(2)(v)(D), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

alarm. A fire damper inspection was being performed that opened a Control Room HVAC ductwork access hatch that caused the alarm. The hatch was opened and immediately shut, re-establishing the boundary of the Control Room Envelope (CRE). The Control Room Emergency Ventilation (CREV) system was declared inoperable due to opening the ventilation duct hatch without prior administrative controls in place. As a result, Technical Specification 3.7.4, Condition C, was entered and subsequently exited within approximately one minute.

The cause of the inadvertent CRE breach was the design drawing contained in the work package that was reviewed during the Plant Barrier Impairment (PBI) screening did not adequately define the boundaries of the CRE.

Corrective actions included reviewing all open PBI packages. Associated Control Room boundary drawings and procedures will be revised to correctly annotate the proper CRE boundary to include the MCR ventilation ductwork access hatch.

The safety significance of this event was minimal. Given the impact on the MCR envelope, this report is submitted (for Units 1 and 2) in accordance with the requirements of 10 CFR 50.73 (a)(2)(v)(D), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

On 03/21/15, at 0800, with Unit 1 shutdown for refuel outage Q1R23, the Unit 1 Off-Line Automatic Blowdown Logic Test was being performed when two Electromatic Relief Valves (ERVs) failed to actuate since the 'N trip logic for the automatic function of the Automatic Depressurization System (ADS) did not energize.

Maintenance burnished the 'A' trip logic relay contacts and the 'B' trip logic relay contacts. The as-found data on the 'B' trip logic of ADS was lost during this troubleshooting, and it is unknown if the 'B' trip logic of the automatic function would have functioned. Once the relay contacts were burnished, the continuity was checked and found acceptable.

The apparent cause for the loss of the 'A' trip logic system was due to relay contact oxidation buildup. The oxidation buildup was due to inadequate preventative maintenance instructions.

The immediate corrective action consisted of burnishing the relay contacts. Future corrective actions include updating the preventative maintenance procedure and replacing the two relays on the 'A' trip logic system that had the oxidation buildup.

This report is submitted in accordance with 10 CFR 50.73 (a)(2)(v)(D) which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident; and 10 CFR 50.73 (a)(2)(vii)(D) which requires the reporting of any event where a single cause or condition caused two independent channels to become inoperable in a single system designed to mitigate the consequences of an accident.

On February 10, 2015, at 1055 hours, a maintenance individual notified the control room that both doors in the secondary containment interlock between the Reactor Building (RB) Unit 1 High Pressure Coolant Injection (HPCI) room and the Unit 1 Turbine Building (TB) were opened simultaneously. The failure of this interlock caused a loss of secondary containment (inoperable) per Technical Specification (TS) 3.6.4.1, Condition A. The RB-side door was immediately reclosed, and the secondary containment boundary was reestablished. Operators verified the RB (secondary containment) differential pressure remained negative during this event.

Secondary containment remained available and functional during the event since the secondary containment interlock was immediately restored by closing the RB-side door and the RB differential pressure was maintained during the event. No RB low differential pressure alarms were received during this event. The RB is a common volume to both Units 1 and 2, and an interlock failure can impact the secondary containment for both units.

The cause of the interlock failure was due to a bent locking bolt with insufficient strength to withstand the standard practice of challenging that fire doors are locked closed after passing through them. The bent locking bolt caused its door plungers to not engage allowing its door to open while the opposite door in the interlock was being opened.

Corrective actions included repairing the bent locking bolt on the TB-side passive door and realigning the TB-side doors to ensure the plungers would be functional. The locking bolt will be replaced with a higher strength assembly.

The safety significance of this event was minimal.

Given the impact on the secondary containment, this report is submitted (for Units 1 and 2) in accordance with the requirements of 10 CFR 50.73 (a)(2)(v)(C), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

On January 6, 2015, Electrical Maintenance was preparing for planned maintenance activities at a 480V Motor Control Center (MCC). One of the technicians identified that the breaker in cubicle Al was in the tripped position. Breaker Al is the Unit 2 power supply breaker to the Unit 0 Fuel Oil Transfer Pump (FOTP) for the Unit 0 Emergency Diesel Generator (EDG).

Troubleshooting identified the cause of the breaker trip was due to high resistance contacts on the HGA power transfer relay. This relay was replaced and tested satisfactory on January 8, 2015.

This breaker most likely tripped under load, which would have occurred during the Unit 0 EDG 24 hour endurance run when the EDG was loaded to Unit 2 on December 30, 2014. Since planned maintenance occurred on the Unit 0 EDG prior to the endurance run, the time of inoperability of the Unit 0 EDG started on December 29, 2014 and ended when the failed relay was replaced and tested satisfactory on January 8, 2015, for a total of 10 days. This exceeded the allowed outage time of Technical Specifications 3.8.1 for one EDG inoperable. Therefore, this Licensee Event Report is being submitted in accordance with 10 CFR 50.73 (a)(2)(i)(B) for a condition prohibited by Technical Specifications.

NRC FORM 368 (02-2014)

turbine building (TB) doors for the 647 foot elevation secondary containment interlock were opened simultaneously. The failure of this interlock caused a loss of secondary containment per Technical Specification (TS) 3.6.4.1, Condition A. The doors were immediately closed and secondary containment pressure remained negative throughout the event. The Field Supervisor was dispatched to investigate the interlock issue and found that the issue was intermittent. Operators staged signage and ropes to administratively control the interlock closed until repairs were performed.

Secondary containment remained available during the event because the secondary containment interlock was immediately restored by closing the doors, and the RB differential pressure was maintained throughout the event. No RB low differential pressure alarms were received during the event. The RB is a common volume to both Units 1 and 2, and an interlock failure can impact the secondary containment for both units.

The cause of the interlock failure was the door magnets on the Unit 2 TB door did not fully engage to hold the door closed due to inadequate design of the interlocks.

Corrective actions included adjustment of the lower magnet on the TB door to ensure good connection between the door and the frame. A modification to the 647 foot elevation interlock doors that addresses single point vulnerabilities will be implemented, and the preventative maintenance frequency will be shortened from 12 months to 6 months.

The safety significance of this event was minimal. Given the impact on the secondary containment, this report is submitted (for Units 1 and 2) in accordance with the requirements of 10 CFR 50.73 (a)(2)(v)(C), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

On May 16, 2014, with Unit 2 at full power, a main condenser flow reversal was performed. During the flow reversal, anomalous indications were noted for the 2C condenser (COND) backpressure response. As a result of the slow response, RPS pressure switch (PS) 2-0503-B was declared inoperable. This pressure switch is one of the inputs into the Reactor Protection System (RPS) (JD) for the Turbine Condenser Vacuum-Low function. The isolation valve (RTV) for this pressure switch was found partially closed. The valve was opened and normal indication was restored.

During the review of this event, it was identified that the RPS pressure switch was inoperable since May 6, 2014. Unit 2 did not meet the required number of channels per TS 3.3.1.1, Function 10, Turbine Condenser Vacuum-Low, when transitioning to MODE 1 at 2252 on May 6, 2014, as required by TS 3.0.4, and did not take the actions required in the allowed outage time.

The safety significance of this event was minimal. Sufficient redundant condenser backpressure instrumentation was operable to maintain scram capability and the RPS safety function. This event is reportable as an operation or condition prohibited by plant Technical Specifications per 10 CFR 50.73(a)(2)(i)(B).

On April 1, 2014, at 1357 hours, an Instrument Maintenance Technician notified the Main Control Room that both doors in the secondary containment interlock on the 595 foot elevation between the Reactor Building (RB) and the Unit 2 Reactor Feed Pump room (located inside the turbine building (TB)) were opened simultaneously. The failure of this interlock caused a loss of secondary containment per Technical Specification (TS) 3.6.4.1, Condition A. The doors were immediately reclosed, and the secondary containment boundary was immediately reestablished.

Operators verified the RB (secondary containment) differential pressure was maintained operable at greater than 0.10 inch of vacuum water gauge.

Secondary containment remained available and functional during the event since the secondary containment interlock was immediately restored by closing the doors and since the RB differential pressure was maintained during the event. No RB low differential pressure alarms were received during this event. The reactor building is a common volume to both Units 1 and 2, and an interlock failure can impact the secondary containment for both units.

The cause of the interlock failure was due to a malfunctioning interlock door hydraulic actuator and time delay relays had allowed the second door to open before the first door was secured.

Corrective actions included replacing the failed actuator and adjusting the limit switch. A set point change will be implemented to resolve relay time delay issues.

The safety significance of this event was minimal. Given the impact on the secondary containment, this report is submitted (for Units 1 and 2) in accordance with the requirements of 10 CFR 50.73 (a)(2)(v)(C), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

On March 4, 2014, at 1917 hours, a Fuel Pool Channel 1B High Radiation alarm occurred. The 1B fuel pool radiation monitor spiked high at 50 mRem/hr, trended downward, and returned to its previous steady-state value of 14 mRem/hr. The high spike caused the Unit 1 and Unit 2 Reactor Building (RB) ventilation and Control Room (CR) ventilation to isolate as designed. The Standby Gas Treatment System (SBGTS) was already in operation for a scheduled surveillance as of 1900 hours on March 4, 2014.

The Unit 1 and Unit 2 RB ventilation system isolation caused the secondary containment differential pressure to be momentarily lost (pressure went positive), and secondary containment was declared inoperable. The RB ventilation system was then shut down for scheduled maintenance, the CR ventilation system was returned to its normal configuration, and troubleshooting was initiated.

Since both Units 1 and 2 share a common RB, the loss of differential pressure (RB pressure went positive) for approximately three (3) minutes impacted both Units 1 and 2 secondary containments.

The cause of the secondary containment loss of differential pressure event was due to a failed fuel pool radiation monitor detector that caused the RB ventilation system to isolate. The detector failure was caused by a manufacturing defect that caused double pulsing on the GM-Tube.

Corrective actions included replacing the failed radiation monitor detector, and sending the failed detector to the vendor for failure analysis.

The safety significance of this event was minimal. Given the impact on the secondary containment, this report is submitted (for Units 1 and 2) in accordance with the requirements of 10 CFR 50.73 (a)(2)(v)(C), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

On March 11, 2013, during refueling outage Q1R22 at approximately 0750 hours, the Unit 1 Main Steam Isolation Valve (MSIV) as-found stroke time test results indicated that all four outboard MSIVs failed to close within the required Technical Specification (TS) time of less than or equal to five (5) seconds. The four inboard MSIVs, tested just prior to the outboard MSIVs, all closed within the required TS time of less than or equal to five (5) seconds. The safety significance of this event was minimal.

The cause of the Unit 1 outboard MSIV slow closure timing is the actuator seals had degraded due to age and wear.

Corrective actions included replacing the 1-0203-2B MSIV actuator, readjusting as-left closure times on all outboard MSIVs, and satisfactory retesting prior to startup. Follow-up corrective actions include replacing the 1-0203-2A, 2C, and 2D MSIV actuators and increasing the preventive maintenance frequency.

Since all four outboard MSIVs failure to stroke within the required times was attributed to degraded actuator seals, it is likely the degradation occurred over time since the last successful refueling outage testing and during power operations when the required TS 3.6.1.3, Primary Containment Isolation Valves (PCIV5), was applicable.

Therefore this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B), which requires reporting of any operation or condition that was prohibited by the plant's Technical Specifications.

On April 18, 2012, at 1511 hrs, while at low power conditions after refueling outage Q2R21, an automatic reactor scram occurred on Unit 2 due to high reactor pressure. The pressure increase occurred during post-modification testing on the main generator automatic voltage regulator (AVR) which had been upgraded during refueling outage Q2R21. The testing included a generator load reject, which was in progress when the pressure transient occurred. There were no complications during the reactor scram and subsequent turbine trip, and all systems functioned as required. Operators performed required actions safely and in accordance with procedures and training.

The cause of the automatic scram was due to high reactor pressure created by the load rejection associated with the main generator voltage regulator testing, coincident with unresponsive opening demand of turbine control valves (TCVs) that impacted the turbine bypass valves (TBVs) ability to control reactor pressure. Since the digital electro hydraulic control (DEHC) system design lacked the required Intercept (IV) EHC shutoff valves, this resulted in low EHC pressure and caused the TCVs to be unresponsive. Unit 1 was unaffected by the event and remained at 100% power.

Corrective actions included evaluating the impact of the event on the operability of the TBVs, and applying a Minimum Critical Power Ratio (MCPR) Operating Penalty (TS 3.7.7) when reactor power is between 25% and 50%. Future corrective actions include development of a hardware/software modification to the DEHC system to correct the design deficiency.

The safety significance of this event was minimal. This event is reportable (Unit 2) per 10 CFR 50.73(a)(2)(iv)(A), which requires the reporting of any event or condition that resulted in manual or automatic actuation of the reactor protection system (RPS), including reactor scram; (Units 1 and 2) 10 CFR 50.73(a)(2)(i)(B), which requires the reporting of any operation or condition which was prohibited by the plant's Technical Specifications; and (Units 1 and 2) 10 CFR 50.73 (a)(2)(v)(C), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems needed to control the release of radioactive material.

On July 6, 2011 at 1410 hours, the Unit 1/2 (common) "B" Control Room Emergency Ventilation (CREV) Refrigeration Condensing Unit (RCU) was declared Inoperable due to an increase in vibration amplitude caused by a broken chiller compressor connecting rod. Operators performed required actions to safely secure the CREV RCU in accordance with procedures and training, and without complications. This resulted in entering Technical Specification 3.7.5, Condition A (30 day Action). This event affected both the Unit 1 and Unit 2 Control Rooms since they share a common control room and CREV system.

The Train B CREV Air Conditioning (AC) system is a single train safety-related system that is designed to operate in a post- accident condition to maintain design temperature in the Control Room Envelope (CRE), and loss of the CREV AC could impact the plant's ability to mitigate the consequences of an accident.

The CREV RCU chiller compressor connecting rod failure was caused by flooded starts of the compressor. The root cause of the flooded start was an unanticipated failure mode for the design application of the system.

Corrective actions included replacing the failed compressor with a new compressor, and revising the frequency for vibration analysis on the B CREV RCU to monthly. Future corrective actions include installation of an automatic pump-down modification for the B CREV RCU compressor.

The safety significance of this event was minimal.

Given the impact on the CREV AC system, this report is submitted in accordance with the requirements of 10 CFR 50.73(a)(2)(v)(D), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

On April 19, 2011, at 1430 hours, a water leak was discovered on the Unit 1 Emergency Diesel Generator Cooling Water Pump (EDGCWP) room cooler. As a result, the Unit 1 EDG (Division II) was declared inoperable and Technical Specification (TS) 3.8.1 was entered. (ENS Report No. 46769) At this time, Division I Residual Heat Removal (RHR) was inoperable for planned maintenance on the Division I RHR room cooler. In the event of a LOOP/LOCA scenario, RHR would not have been able to perform its safety function (i.e., Division I RHR was impacted by the ongoing room cooler maintenance and Division II RHR would not have had an operable on-site emergency power source). Note that at the time of discovery, offsite power was available to Division II RHR as well as the Division I and Division II Core Spray systems.

At 1816 hours, the Division I RHR system room cooler was restored and Division I RHR was declared operable.

The room cooler leak was caused by under-deposit corrosion on the piping due to raw water conditions. The through wall leak on the cooler was subsequently repaired and the Unit 1 EDGCWP room cooler was returned to operable status on April 21, 2011.

Given the impact on the RHR system, this report is submitted in accordance with the requirements of 10 CFR 50.73(a)(2)(v)(D), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

On October 8, 2004, at 0300 hours, it was determined that the Control Room Emergency Ventilation System (CREVS) Test had not been performed correctly during the last performance, and TS Surveillance Requirement (SR) 3.0.3 was entered for a missed surveillance.AAt 2120 hours, the surveillance was performed and the pressure differential was determined to be less than required.A The CREVS was declared inoperable, TS SR 3.0.3 was exited and TS Action 3.7.4.A was entered. At 2158 hours, an Emergency Notification System call was made in accordance with 10CFR50.72(b)(3)(v)(D) for loss of safety function of a single train system. The seals for two hatch covers were enhanced and the test was re-performed successfully.AOn October 9, 2004, at 0400 hours CREVS was declared operable.

This event was caused by an inadequate review of a procedure change in 1998, and a deficient modification to the hatch covers in 1999. Corrective actions include enhancements to the seals and a procedure change to add flow criteria to the test procedure.

The safety significance was minimal because CREVS does not impact reactor safety and the Control Room Emergency zone differential pressure was positive at all times.