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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.

On April 2, 2014, at 1228 hours, a Fire Alarm System (FAS) alarm was received for the Unit 2 D heater bay area. Although entry into the room at the time identified only a steam leak, subsequently various spurious alarms and electrical system anomalies occurred.

At 1303 hours, Unit 2 was manually scrammed, the turbine was tripped, and the main steam isolation valves (MSIVs) were closed to ensure the steam leak was isolated. A fire was identified to have occurred in the D heater bay (an area of the plant containing the high pressure (final stage) D feedwater heaters, and several Unit 2 cable trays and risers). The fire was extinguished by the automatic wet pipe sprinkler fire suppression system.

At 1340 hours, due to the manual de-energizing of safety-related motor control center (MCC) 29-1 in the reactor building in response to notification that smoke had been observed, an ALERT level Emergency Action Level classification was declared as HA3 (fire in a vital area affecting safety system equipment). The emergency was terminated at 2132 hours.

The cause of the event was an existing cable flaw that was caused by cable routing that exceeded the required minimum static bend radius.

Corrective actions included repairing impacted cables, replacing the failed steam seal expansion joint, operating procedure revisions, and additional inspections/tests.

The safety significance of this event was minimal. Given the impact on multiple systems, this report is submitted in accordance with 10 CFR 50.73 (a)(2)(iv)(A) for manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B); in accordance with 10 CFR 50.73 (a)(2)(v)(D) for an event that could have prevented the fulfillment of the safety function of systems needed to mitigate the consequences of an accident; and in accordance with 10 CFR 50.73(a)(2)(i)(A), for the completion of a nuclear plant shutdown required 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.

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On January 12, 2011, at 1020 hours, the Unit 2 Essential Service (ESS) 480V Bus 29 (BU) was inadvertently de-energized. The cause of this bus trip was due to inadvertent contact with the bus feed breaker local trip pushbutton (JS) by a station employee during unrelated work activities in the bus feed breaker area. While Bus 29 was de-energized, Division II core and containment cooling systems (BO) were unavailable and inoperable; however, normal power to Bus 29 was restored within 6 minutes.

The plant responded as designed to the loss of Bus 29, with the exception that the normally supplied reactor building ESS 480V Bus Motor Control Center (MCC) 28/29-5 did not receive the auto transfer of supplied power from its reserve feed 480V Bus 28.

Since either 480V Bus 29 or Bus 28 can feed Bus 28/29-5, this condition resulted in a loss of power to Bus 28/29-5 and rendered both divisions of the Low Pressure Coolant Injection (LPCI) (BO) mode of the Residual Heat Removal (RHR) (BO) system inoperable. Therefore, Technical Specification 3.5.1.E was entered, requiring restoration of LPCI within 72 hours.

It was subsequently determined that the "M" auxiliary contactor (CNTR) from Bus 29 had failed which caused the auto transfer logic from Bus 29 to Bus 28 to fail.

Bus 28/29-5 was manually reenergized from Bus 28 at 1213 hours; however, LPCI remained inoperable pending investigations.

Restoration of Bus 28/29-5 auto-transfer function occurred at 2151 hours, allowing LPCI to be returned to operable status and TS 3.5.1.E to be exited.

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 9, 2004, during a refueling outage on Unit 2, axial flaws were detected during a scheduled Inservice Inspection (ISI) of a recirculation system weld (02B- S7). Although the axial indications could not be fully characterized using qualified Performance Demonstration Initiative inspection techniques, the flaw sizes were estimated to be approximately 0.35 and 0.25 inches long and approximately 0.39 inches deep (not through-wall).

The axially oriented intergranular stress corrosion cracking (IGSCC) flaws were most likely detected as a result of the decontamination process increasing the reflectivity of the pre-existing flaws. IGSCC mitigation efforts such as hydrogen water chemistry, noble metals chemical addition and mechanical stress improvement process had previously been applied to this weld, and the probability that cracking occurred following these mitigation efforts is low. It is most likely that the flaws were present but not previously detected.

An overlay was applied to weld 02B-S7 in accordance with industry guidance, and the other four Unit 2 Category D welds were inspected with no additional flaws identified.

was shut down to allow inspection and repair of the steam dryer. On June 12, 2003, inspections identified cracking in the steam dryer. Failure analysis and repairs to the Unit 2 dryer were completed over the following 18 days and the reactor was returned to service.

The root cause of the failure of the steam dryer has been determined to be the high cycle fatigue cracking caused by the increased vibration loadings created by high steam velocities.

The safety significance of this event was minimal. The dryer is a non-safety related component whose only safety function is to remain intact such that it will not prevent a safety related component from performing its function. At the time of discovery, all dryer components remained constrained within the dryer/separator envelope.

This report is being submitted as a voluntary report.

On April 16, 2003, at 1322 hours, the Unit 2 3B Main Steam Relief Valve (RV) self- actuated. The operators initiated the appropriate procedures for an open RV, including initiation of suppression pool cooling, a manual reactor scram, removal of the control power fuses to the 3B RV, and closure of the main steam isolation valves to slow the reactor cooldown rate. At 1359 hours, the suppression pool temperature reached 110F and an Alert was declared in accordance with the Exelon Emergency Plan.

The Alert was exited at 2251 hours.

The safety significance of this event was minimal. The opening of the 3B RV did not affect the capability of the relief valves to protect against high reactor pressure.

At the time of the event, the M Emergency Diesel Generator was out of service for planned maintenance. All other mitigating systems were available. Therefore, both emergency and non-emergency sources of injection to the vessel were available to make up for the coolant being relieved through the RV to the suppression pool.

The root cause was excessive leakage past the 3B RV pilot valve seat, which allowed the RV closure force to diminish and the RV to open. Corrective actions included replacement of the 3B RV, improvements in RV tailpipe temperature monitoring, and removal of the requirement to perform on-line test actuations of the RV.

On October 7, 2002, at 1044 hours, a detached wire was found in a panel in the auxiliary equipment room as the result of a logic test failure. With the wire detached, one division of the Low Pressure Coolant Injection (LPCI) system would not have automatically started, and the flow from the other division may have been diverted from the reactor vessel. All pumps and valves could have been operated manually from the control room control panels and plant operators would have been able to restore required flow to the vessel.

The detached wire was determined to be due to poor installation of the wiring and a lack of formal expectations concerning the inspection of equipment disturbed during work activities. Corrective actions include attaching the wire correctly and establishing and implementing expectations concerning the performance of inspections for electrical components and equipment following work activities.

On April 5, 2002, at 1028 hours, a manual scram was inserted on Unit 2 in response to increasing reactor level. The increase in reactor level was due to a blown fuse in the Digital Feedwater Level Control (DFWLC) system, caused by the inadvertent grounding of test leads during an instrument surveillance. Although the DFWLC logic is intended to be able to respond to a blown fuse without causing a level transient, the indicating fuse holder provided a circuit that inhibited recognition of the blown fuse by the DFWLC logic.

The root cause of the Unit 2 reactor scram was a design deficiency involving the installation of indicating fuse holders. The inadvertent grounding of the test leads was a contributing cause. Also, although the operator actions were in accordance with procedure, different actions may have mitigated this event.

The safety significance of this event was minimal. Adequate makeup to the vessel was available at all times from the feedwater system, as well as from the ECCS systems.

Corrective actions include removal of the indicating fuse holders, actions to minimize the potential for grounding test leads, and review of the default operator actions for a level transient.

On August 2, 2001, at 0813 hours, lightning struck a 345 kV line that connected to the Quad Cities switchyard. This resulted in failure of the Unit 2 Main Power Transformer (MPT), an automatic reactor scram on Unit 2 and loss of normal offsite power to Unit 2. An Unusual Event was declared, the Unit 2 and 1/2 Emergency Diesel Generators started, and the Reactor Core Isolation Cooling system and the Safe Shutdown Makeup Pump were manually started to maintain reactor vessel level. The MPT fire was extinguished at 0845 hours and normal offsite power was restored to Unit 2 at 1047 hours.

The safety significance of this event was minimal. All safety systems operated as designed to shut the Unit 2 reactor down and maintain it in a safe shutdown condition. Offsite power was available to Unit 2 from the Unit 1 Reserve Auxiliary Transformer through the emergency bus crosstie throughout the event.

The root cause of the MPT failure was mechanical failure of the bus bar clamps due to original equipment manufacturer design and construction errors. The root cause of the loss of normal offsite power was age degradation in a Static Breaker Failure (SBF) relay.

The SBF relay was replaced and the preventive maintenance program has been upgraded concerning local breaker backup schemes. The MPT Specification Development Lessons Learned Review Checklist has been upgraded and a comprehensive transformer monitoring strategy will be implemented.

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