Semantic search

On November 9, 2017 at approximately 2300, Salem Unit 1 was operating in MODE 3 when operators found steam leaking into the mechanical penetration area outside containment. Operators entered S1.0P-AB.STM-0001, Excessive Steam Flow, and dispatched operators to locate and isolate the leak.

Operators determined the steam was from the 14 steam generator through normally closed valves 14GB47 and 14GB48 steam generator blowdown (WI) line nitrogen supply valves. The steam leak was isolated at 2314 when operators closed normally open manual valve 14GB3.

This report is made per 10CFR50.73(a)(2)(i)(B), Any operation or condition which was prohibited by the plants Technical Specifications.

This was caused by human performance. Procedures will be revised to assure containment integrity exceptions are tracked and open valves are closed while sampling during the sparging process.

NRC FORM 3116 (04-20171

On October 31, 2017, while in Mode 6 and at 0% power level, the Turbine-Driven Auxiliary Feedwater (TDAFW) pump B-Train steam admission valve from the 2C Steam Generator failed to meet Technical Specification ('I'S) Surveillance Requirement (SR) 3.7.5,5. This SR requires that the valve's associated air accumulator provide sufficient air to ensure operation of the TDAFW pump during a loss of power or other failure of the normal air supply.

During the performance of a flow scan analysis it was identified that the air-operated actuator piston was leaking by the actuator ' o-ring. Although the steam admission valve would stroke open, the 2-hour acceptance criteria could not be met. It is likely that the steam admission valve was inoperable longer than allowed by the Required Action Statement (7 days) following the spring 2016 refueling outage when it passed its last associated surveillance. Therefore, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.

Corrective actions included actuator repair during the outage and further evaluating the preventive maintenance frequency.

NRC FORM 386 (04.2017)

On November 3, 2017, at 2022 hours, with reactor power at 100 percent, Indian Point Unit 3 experienced an automatic reactor trip on a turbine trip, which was in response to a main generator trip. The main generator trip was initiated by actuation of the Generator Protection System due to a main generator loss of field.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The Auxiliary Feedwater System (AFWS) automatically started as expected on steam generator low level to provide feedwater flow to the steam generators. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the loss of main generator field was a failed Thyristor Firing Module drawer which affected proper operation of the redundant Thyristor Firing Module drawer. The root cause was determined to be that the Automatic Voltage Regulator (AVR) Firing Module power supplies have a latent design vulnerability where shared common output nodes are not isolated after a failure. A plant modification is proposed that will eliminate the condition by electrically isolating the AVR Firing Module power supplies upon failure.

This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on November 3, 2017 under 10 CFR 50.72(b)(2)(iv)(B) and 50.72(b)(3)(iv)(A) as an event that resulted in the automatic actuation of the Reactor Protection System when the reactor is critical and a valid actuation of the AFWS.

On October 29, 2017, Unit 1 entered MODE 3 from MODE 4 without satisfying all of Technical Specification 3.7.5, Auxiliary Feedwater (AFW) Limiting Conditions for Operation (LCO) as required by LCO Applicability 3.0.4 for the Turbine Driven Auxiliary Feedwater (TDAFW) pump system.

LCO Applicability 3.0.4 does not permit entry into a MODE of applicability when an LCO is not met, unless the associated actions to be entered permit continued operation in the MODE for an unlimited time or after performance of an acceptable risk assessment and the appropriate risk management actions have been established. After entering MODE 3, it was discovered that components were not operable, contrary to LCO 3.0.4.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B), for an operation or condition prohibited by Technical Specifications.

On September 10, 2017 at approximately 1855 hours, the Turkey Point Unit 4 reactor was manually tripped from 88% power due to lowering level in Steam Generator (SG) C. The reactor was stabilized in Mode 3.

Auxiliary Feed Water actuated as expected on low level in SG C and was secured at approximately 1933 hours. At the time of the event, the Turkey Point site was experiencing high winds with rain associated with Hurricane Irma. The B and C Main Feedwater Regulating Valves (MFRV) had been in manual control when the C MFRV failed closed. The cause of the event was a degraded signal due to water intrusion into the C MFRV valve positioner hand selector switch enclosure resulting from a less than adequate design and installation. Corrective actions include modifications to the Unit 3 and 4 MFRV hand selector switch enclosures and enclosure penetrations, and repair of a failed component associated with the 4C MFRV. Additionally, the terminal/pull box specifications will be revised to improve direction for installation activities. Safety significance is very low because the unit responded as designed to the trip.

On October 26, 2017, at 0212 hours with St. Lucie Unit 2 in Mode 1 at 100% power, the reactor automatically tripped due to a loss of load following a failure within the turbine control system. The reactor trip was uncomplicated and all control rod assemblies fully inserted. Following the trip, one of the low power feedwater valves LCV-9005, did not properly maintain steam generator level which resulted in an actuation of the A-train auxiliary feedwater system. During the auxiliary feedwater actuation, one main feedwater isolation valve did not reposition closed as expected, but this did not impact heat removal. The main feedwater system remained available.

The failure within the turbine control system was caused by design deficiencies. Planned corrective actions include modifications to improve protective circuits, the addition of coolers and use of conformal coatings on printed circuit boards in the modules.

The problem with LCV-9005 was due to a latent design error that resulted in the setting of an incorrect stroke length for the control valve. This was corrected by adjusting the stroke length of the valve.

This report is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) for system actuations of the reactor protection system and the auxiliary feedwater system.

During this event offsite power remained operable and energized. All other equipment responded to the event as expected per the existing plant conditions; therefore, this event had no impact on the health and safety of the public.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Description On October 26, 2017, at 0212 hours with St. Lucie Unit 2 in Mode 1 at 100% power, the reactor automatically tripped due to a loss of load following a failure within the non-safety related turbine control system (TCS) (EIIS:TG:DCC). Based on initial investigation, it was determined that a TCS malfunction affected multiple testable dump manifold (TDM) solenoids (EIIS:TG:PSV). Ultimately, electro-hydraulic (EH) (EIIS:TG) system pressure was lost (i.e., turbine tripped) after two TDM 1 solenoids spuriously operated concurrently. All high pressure turbine governor and throttle valves (EIIS:TA:XCV) and all low pressure turbine intercept and reheat stop valves (EIIS:TA:SHV) repositioned closed as expected upon loss of EH pressure. The reactor trip was uncomplicated and all control rod assemblies fully inserted.

Following the reactor trip, the 15% bypass feedwater regulating valve, LCV-9005 (EIIS:JB:LCV), did not provide the expected feedwater flow to the 2A Steam Generator (EIIS:JB:SG). This resulted in lowering steam generator level and an actuation of the A train auxiliary feedwater actuation system (AFAS) (EIIS:JC). During the auxiliary feedwater actuation, one main feedwater isolation valve (MFIV) (EIIS:JB:ISV), HCV-09-1A, did not reposition closed as expected, but this did not impact heat removal as the redundant MFIV in series isolated main feedwater. The main feedwater system remained available.

Cause of the Event

The failure within the turbine control system was caused by design deficiencies. The TCS incorporates various features for fault tolerance, including the use of three separate trip circuits for each TDM, the 2 out of 3 hydraulic logic of the TDM design, and redundant datalinks provided for Remote I/O communications. The design is intended to ensure a single failure or malfunction will not result in turbine trip. Replaced modules were retained for analysis. Two sets were sent to the original equipment manufacturer. The third set was sent to an independent lab for forensic analysis. Based on the results of the forensic analyses, this report may be supplemented with additional causal factors as appropriate.

The problem with LCV-9005 was due to a latent design error that resulted in the setting of an incorrect stroke length for the control valve. The stroke length of LCV-9005 has been properly adjusted.

The problem with HCV-09-1A was caused by a failed solenoid, and the solenoid was replaced.

Analysis of the Event

This licensee event report is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as “Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B).” This event included automatic actuations of the reactor protection system and the auxiliary feedwater system.

Testable Dump Manifolds The TCS has automatic control and trip devices necessary for operation and protection of the turbine-generator.

An automatic trip is provided to prevent any damage to the turbine-generator. The unit trips upon occurrence of conditions which are potentially hazardous to the turbine-generator or to other associated plant equipment. The TCS uses two headers to provide emergency turbine trip and overspeed protection. The emergency trip header has two testable dump manifolds (TDM 1 and TDM 2) and the overspeed protection header has one testable dump manifold (TDM 3). Each triple redundant electronic emergency trip system uses a TDM to interface with the control oil system. The 2-out-of-3 solenoid logic used to provide a protective trip also provides a means to test the system while on-line.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Reviews of EH pressure data at each TDM showed that TDM 1 solenoid B was momentarily spuriously opening during the night prior to the event, and also that TDM 1 solenoid A and TDM 2 solenoid C had momentarily opened over the same time period. Approximately 30 minutes prior to the trip, TDM1 solenoid B opened and stayed open, putting TDM 1 into a continuous half trip state. The trip occurred after a second solenoid on TDM 1 spuriously opened.

Auxiliary Feedwater Actuation LCV-9005 and LCV-9006 are a pair of non-safety related 15% bypass feedwater regulating valves supplying main feedwater flow to the 2A and 2B SGs respectively with a predetermined set point and flow rate post trip. In 1997, LCV-9005 was replaced with what was intended to be a like for like valve replacement. However, the replacement LCV-9005 had different flow characteristics and a different stroke length that was not properly documented; therefore, not properly setup.

Prior to its replacement in 1997, LCV-9005 had a stroke length of 1.5 inches. The replacement valve had a stroke length of 2 inches. Stroke length is used to set up the control of the valve flow rate characteristics.

Therefore, the new model valve was only opening a percentage of a 1.5 inch stroke length instead of 2 inches.

This resulted in less flow than needed to automatically maintain flow to the steam generator without manual operation. A change in the plant conditions following implementation of a low power feedwater digital controller in 2013 compounded the effect of shortened valve stroke length that became apparent during this plant trip.

The opposite train valve LCV-9006 was determined to be operating with the proper stroke length, and main feedwater was used to feed the 2B Steam Generator post trip.

Safety Significance

The digital signals sent by the TCS to the TDMs during this event were reviewed and determined to be invalid and spurious. The turbine was not damaged or exposed to hazardous conditions during this event.

The auxiliary feedwater system is provided with complete sensor and control instrumentation to enable the system to automatically respond to a loss of steam generator inventory. Due to the incorrect setting of LCV- 9005 and the lowering water level in the 2A steam generator, the AFAS-1 actuation was valid. Once the mismatched 15% bypass feedwater regulating valve was isolated by AFAS-1, water level in the 2A steam generator was restored using auxiliary feedwater. 2B steam generator level was maintained post trip via LCV- 9006 and main feedwater.

During the auxiliary feedwater actuation, one of two MFIVs did not reposition closed as expected. There are two MFIVs in series on each feedwater train (A and B). The 2A train of main feedwater was automatically isolated by at least one MFIV. The Unit 2 UFSAR Table 7.3-12 describes failure modes and effects for the auxiliary feedwater actuation system. This analysis bounds the observation of the event described in this LER.

During this event offsite power remained operable and energized. Loss of turbine load events are bounded in the UFSAR as anticipated operational conditions. All other equipment responded to the event as expected per the existing plant conditions; therefore, this event had no impact on the health and safety of the public.

Corrective Actions

The corrective actions listed below are either completed or are being managed under the Corrective Action Program:

1. The three digital output modules controlling solenoids for TDM 1 were replaced, each consisting of an Electronics Module (EMOD), Personality Module (PMOD) and base assembly.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

2. The digital output module EMOD and PMOD for TDM 2 solenoid C was also replaced, as there was evidence that this solenoid had spuriously opened prior to the event.

3. The removed digital output modules were retained for analysis. Two sets (EMOD/PMOD/Base) from TDM 1 were sent to Emerson. The third set from TDM 1 was sent to an independent lab for forensic analysis.

4. Additional countermeasures measures were taken to further protect the TCS remote I/O cabinets from the environment. This included improving the remote TCS cabinets' environmental protection.

5. Actions are planned to install coolers for TCS cabinets.

6. Actions are planned to replace circuit card components in Remote I/O Cabinets.

7. Actions are planned to implement redundancy and diagnostics modifications to the TCS.

8. The stroke length of LCV-9005 was properly adjusted for a 2-inch stroke.

9. The failed solenoid on HCV-09-1A was replaced.

Failed Components Identified Turbine Control System Digital Output Module - Electronics Module (EMOD) Description: Digital Output 5-60VDC EMOD Manufacturer: Emerson Emerson Style Number: 1C31122G01 EMOD Serial Number: 3611019514 Emerson EMOD Module Revision 10 Turbine Control System Digital Output Module - Personality Module (PMOD) Description: Digital Output PMOD Manufacturer Emerson Emerson Style Number: 1C31125G02 PMOD Serial Number: T104316024 Emerson PMOD Module Revision 06 15% Bypass Feedwater Regulating Valve Manufacturer: Fisher Controls Co Inc. (Emerson) Valve Serial Number: 4” - 52A7148 Main Feedwater Isolation Valve Solenoid Description: valve:solenoid,3-way, 1/8" FNPT conn, carbon steel, 120 VDC,90 psi, normally closed Manufacturer: Parker Hannifin Part Number V5H71970 Cat ID322057-1

Additional Information

None

On August 15, 2017, Callaway Plant was in Mode 1 at 100 percent power. During evaluation of protection for safety-related equipment from the damaging effects of tornados, Callaway Plant personnel determined that the minimum-flow recirculation lines for the turbine-driven auxiliary feedwater pump (TDAFP) and both motor-driven auxiliary feedwater pumps (MDAFPs) could be damaged if a postulated tornado-generated missile were to penetrate the condensate storage tank (CST) valve house and strike the lines. In response, Operations declared all three auxiliary feedwater pumps inoperable.

Compensatory measures were implemented consistent with Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance." Upon completion of the initial compensatory measures, the TDAFP and MDAFPs were declared Operable but nonconforming.

Subsequent to the condition identified on August 15, 2017, continued investigation of tornado missile vulnerabilities led to discovery that the exposed steam exhaust stacks for the main steam safety valves and atmospheric steam dump valves, as well as the exposed vents for the diesel generator fuel oil storage and day tanks, were also susceptible to tornado missile damage to the extent that compliance with General Design Criterion 2 is not ensured. Compensatory measures were then promptly implemented for these conditions, as well, in accordance with EGM 15-002 such that the affected systems have been evaluated to be nonconforming but Operable.

It has been determined that the identified noncomformances are an original plant design legacy issue. Long-term resolution for establishing compliance is under development and will be completed within the time frame described in the EGM.

During an investigation of a nitrogen leak inside the Unit 2 containment, Nitrogen Accumulator Relief Valve (RV) RV-355 was found to be leaking. The leak caused the pressure in the back up nitrogen accumulator supply to Power Operated Relief Valve (PORV) PCV-455C to decrease to a level that made the PORV inoperable. Based on a review of the ti-end data for nitrogen usage in the containment, it is conservatively assumed that RV-355 had been degraded since December 1, 2016, rendering the PORV inoperable for longer than permitted by Technical Specifications.

The presumptive cause was inadequate instructions provided in plant procedures for placing a new nitrogen bottle in service. These instructions did not provide a sequence that assures system pressure transients are mitigated. This may have caused excessive pressure excursions resulting in multiple lifts of RV-355 which resulted in damage to the RV 0-ring seat and a nitrogen leak path.

Corrective actions include replacing RV-355 and revising procedures to provide instructions on placing nitrogen supply bottles in service to maintain back pressure and minimize pressure transients on the nitrogen system.

This event did not affect the health and safety of the public.

On July 17, 2017, at 1606 CDT, Waterford 3 experienced an automatic reactor scram due to a loss of forced circulation, which was the result of a loss of off-site power to the safety and non-safety electrical busses. Prior to the scram, plant operators manually tripped the main turbine and generator due to overheating of the isophase bus duct due to the failure of a shunt assembly connection in the duct to Main Transformer 'B'. The automatic electrical bus transfer did not occur due to relay failures in the fast dead bus transfer system. Both 'A' and 'B' Emergency Diesel Generators started and loaded as designed to re-energize the 'A' and 'B' safety busses. The loss of off-site power caused a loss of both Main Feedwater pumps, resulting in an automatic actuation of the Emergency Feedwater system.

The Root Cause of this event was the design change procedure used for modifications to the fast dead bus transfer circuitry did not include guidance to detect the susceptibility of the relays to DC coil inductive kick. The faulty relays in the fast bus transfer circuit were replaced prior to plant startup.

An Unusual Event was declared at 1617 CDT due to loss of off-site power to safety buses for >15 minutes.

All required safety-related equipment responded as expected during this event.

On September 1, 2017 CPNPP Unit 2 was manually tripped by Control Room Operators due to two dropped rods. All safety systems responded as designed including the automatic start of the Auxiliary Feedwater System. The proximate cause of the dropped rods was a high resistance condition on a single phase of a three phase fusible knife switch in a Rod Control System Power cabinet. Subsequent third party cause analysis was unable to determine the root cause of the high resistance condition. The defective switch was replaced.

Additional corrective actions to avoid recurrence have been entered into the CPNPP Corrective Action Program.

All times below are in Central Standard Time (CDT).

At time 2140 (CDT) on September 1, 2017, CPNPP Unit 2 experienced two (2) dropped rods, one control, one shutdown. The reactor was then manually tripped. The Auxiliary Feedwater system automatically started as expected.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000- Comanche Peak Nuclear Power Plant Unit 2 446

A. REPORTABLE EVENT CLASSIFICATION

The event is reportable under 10 CR 50.73(a)(2)(iv)(A) "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B) of this section." The system which was manually actuated was the Reactor Protection System (RPS). The Auxiliary Feedwater System (AFW) automatically started as designed due to low-low steam generator water level following the trip.

B. PLANT CONDITION PRIOR TO EVENT

At 2140 on September 1, 2017 CPNPP Unit 2 was operating in Mode 1 at approximately 100% rated thermal power.

C. STATUS OF STRUCTURES, SYSTEMS, OR COMPONNETS THAT WERE INOPERABLE AT THE START OF THE

EVENT AND CONTRIBUTED TO THE EVENT

There were no structures, systems, or components which were inoperable prior to the event which contributed to the event. Prior to the actual rod drops, the fusible disconnect switch discussed below was performing its design function.

D. NARRATIVE SUMMARY OF THE EVENT, INCLUDING DATES AND APPROXIMATE TIMES

At time 2140 (CDT) on September 1, 2017, CPNPP Unit 2 experienced two (2) dropped rods, one control, one shutdown.

The reactor was then manually tripped by the control room operators. The time difference between the two rod drops was approximately fifteen (15) to thirty (30) seconds. All safety systems responded as designed.

The initial troubleshooting determined the disconnect switch for the Stationary Coils of Rod Control Power Cabinet 2-2BD caused the rods to drop. Further investigation determined the cause of the rod drops was a high resistance connection on the "A" phase of the Rod Control Power Cabinet 2-2BD stationary coil three-phase fusible disconnect switch (EIIS:(AA) (CAB)(JS)). The switch was replaced and and the reactor started up on September 4.

E. THE METHOD OF DISCOVERY OF EACH COMPONENT OR SYSTEM FAILURE, OR PROCEDURAL PERSONNEL

ERROR

Initial indication of rod drop was provided to the Control room operator by an annunciated alarm. Operators confirmed rod drop through Tavg/Tref alarms and lowering of primary pressure. The reactor was manually tripped approximately one minute after the initial rod dropped (times as indicated by the plant computer).

II. COMPONENTS OR SYSTEM FAILURES

A. CAUSE OF EACH COMPONENT OR SYSTEM FAILURE

A third-party failure analysis identified damage to the "A" phase switch knife blade and its associated receiver clip. The "B" and "C" phase knife blades and clips were undamaged and provided no indication as to the cause of the failure of the "A" phase knife blade and clip. All that could be determined was that the "A" phase switch knife blade and clip experienced heat which resulted in a high resistance connection. That high resistance connection resulted in a voltage drop that was sufficient to cause the stationary coils of two control rods to release their control rods, dropping them into the core.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000- Comanche Peak Nuclear Power Plant Unit 2 446

B. FAILURE MODE, MECHANISM, AND EFFECTS OF EACH FAILED COMPONENT

The three-phase fusible disconnect switch is used primarily to provide isolation to equipment requiring three-phase electrical power. The disconnect switch is essentially three manual electrical knife switches mechanically linked to operate in parallel. The knife blades are independently fused and provide continuity to one of the three phases of electrical power to which they are connected. Other than the fuses, the disconnect switch has no automatic functions and is open and shut manually. The disconnect switch associated with Rod Control Power Cabinet 2-2BD is normally shut and is operated solely to provide electrical isolation to the cabinet. The disconnect switch was last operated by CPNPP personnel in support of maintenance on Rod Control Power Cabinet 2-2BD during the April 2017 2RF16 refueling outage.

No maintenance activities were performed on the switch at that time.

The stationary coils associated with Rod Control Power Cabinet are part of the Rod Control System and are normally energized, fail safe (de-energized) to result in rod insertion. In the event described herein, the high resistance condition experienced on the "A" phase of the disconnect switch resulted in a low voltage condition at the stationary coils which resulted in the dropped rods.

The cause of the high resistance and overheating of the disconnect switch could not be determined.

C. SYSTEMS OR SECONDARY FUNCTIONS THAT WERE AFFECTED BY FAILURE OF COMPONENTS WITH

MULTIPLE FUNCTIONS

This event did not involve systems or secondary functions which were affected by the high resistance condition identified with the disconnect switch.

D. FAILED COMPONENT INFORMATION

The failed disconnect switch was style no. 55E-5328 (catalogue no. 2528D 46 E01) provided by Westinghouse.

III. ANALYSIS OF THE EVENT

A. SAFETY SYSTEM RESPONSES THAT OCCURRED

The Reactor Protection System responded as designed to the manual trip input by the plant operators. All plant safety systems responded as designed. Automatic start of the AFW system was the expected response and the system responded as designed.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000- Comanche Peak Nuclear Power Plant Unit 2 446

B. DURATION OF SAFETY SYSTEM TRAIN INOPERABILITY

The event reported herein did not involve the inoperability of any safety system component or system.

C. SAFETY CONSEQUENCES AND IMPLICATIONS OF THE EVENT

The Rod Control Power Cabinet 2-2BD three-phase fusible disconnect switch has no nuclear safety function; its purpose is to isolate power during maintenance. The high resistance experienced by this disconnect switch resulted in two control rods being dropped and necessitated a manual reactor trip. The analysis contained in FSAR 15.4.3 bounds the condition experienced: one analysis considers one or more rod control cluster assemblies (RCCAs) dropped with a given group, and a second analysis considers a dropped RCCA bank. Both cases are considered ANS condition II events (transients not accidents).

No automatic safety functions were exercised other than the expected automatic start of the Auxiliary Feedwater System and all plant safety systems responded as designed during the resultant transient. This event had no impact on nuclear safety, reactor safety, radiological safety, environmental safety or the safety of the public.

IV. CAUSE OF THE EVENT

The cause of the event was a high resistance condition associated with the electrical connection on the "A" phase of the Rod Control Power Cabinet 2-2BD stationary coil three-phase fusible disconnect switch.

V. CORRECTIVE ACTIONS

The defective switch was replaced. In accordance with the CPNPP Corrective Action Program, phase-to-phase voltage readings will be taken for the Rod Control power supplies three-phase fusible disconnect switches of both Units. A periodic maintenance activity to measure phase-to-phase voltage readings will also be developed. All proposed activities will be tracked and managed under the CPNPP Corrective Action Program.

VI. PREVIOUS SIMILAR EVENTS

There have been no similar reportable events at CPNPP in the past three years.

Technical Specification 3.7.6. A pinhole sized through wall leak was discovered on the downstream side of CD-123, the 32 Auxiliary Boiler Feed Pump Bearing Cooling Relief Valve, which was unisolable to the Condensate Storage Tank.

The pinhole leak was identified following the performance of 3PT-Q120B, 32 Auxiliary Boiler Feed Pump Functional Test. All Operability and Acceptance Criteria of 3PT-Q120B were sat. The relief valve was removed from the system and sent to a vendor for evaluation. After the vendor evaluation, it was determined that the valve pinhole area leak was due to a casting defect.

This event was determined to be reportable as a Loss of Safety Function pursuant to10 CFR 50.72(b)(3)(v)(B) - 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 remove residual heat.

RC FORM 366 (04-2017)

On June 26, 2017, Operations commenced a downpower from 100 percent to 93 percent reactor power to support performance of the Main Turbine Stop and Control Valve Test. With reactor power at 94 percent, the 22 Main Boiler Feed Pump Turbine (MBFPT) speed control trouble alarm annunciated coincident with pump speed swings of 800 revolutions per minute (rpm). The operators ceased the downpower and placed the 22 Main Boiler Feedwater Pump (MBFP) in Manual speed control to control the rpm swings. This was unsuccessful, and the rpm swings continued. The 22 MBFPT low pressure (LP) governor valves were observed to be cycling from full-closed to full-open. The decision was made to take local pneumatic control of the 22 MBFP to stabilize pump speed. Two minutes after establishing local pneumatic control, the LP governor valves went to full closed. With the rapid reduction in 22 MBFP speed, the pump was no longer delivering feedwater flow to the SGs. An automatic main turbine runback signal should have been generated on a low speed signal; however, there was no turbine runback actuation. In response, the operators commenced a manual runback to reduce main turbine load, but the decreasing SG levels reached 15 percent, and at 1531 hours a manual reactor trip was initiated.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the reactor trip was that the shoulder screws used on the 22 MBFPT LP governor valve servomotor linkage had backed out and detached. This caused the LP governor valves to fail closed, shutting off the turbine steam supply. This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on June 26, 2017 under 10 CFR 50.72(b)(2)(iv)(B), 50.72(b)(2)(xi), and 50.72(b)(3)(iv)(A).

On June 16, 2017, the station completed a past operability review and determined that an IsAnergency Feedwater Auto Start Actuation Signal was inoperable from November 12. 2016 until April 7. 2017. Technical Specification (TS) 3.3.2 Limiting Conditions for Operation (J,C.0) was entered due to having less than the minimum number of channels operable for Motor Driven Emergency Feedwater Pump (NIDE:MVP) actuation per TS Table 3.3-3 Functional IJnit 6.g.

'Ibis event was caused by the Low Pressure (LP) and High Pressure (HP) steam inlet valves not closing because the Secondary Operating Cylinder and associated Pilot Valve were corroded. Water intrusion into the 'C' Main Feedwater Punip (MFP) oil system had caused the corrosion of the carbon steel components within '1.1)P0022C such that the Secondary Operating Cylinder and Pilot Valve were not functional.

This condition is reportable under 10CFR50.73(a.)(2)(i)(B), an operation or condition which was prohibited by the plant's Technical Specifications.

On April 26, 2017, Arkansas Nuclear One, Unit 1 (ANO-1), was operating normally at 100% rated thermal power.

The 500kV transmission line to the substation at Pleasant Hill, Arkansas was out of service for planned maintenance.

The area around the plant was experiencing severe weather from thunderstorms and tornado warnings had been issued from the National Weather Service for the four county area.

At approximately 1002 CST switchyard breakers for 500kV lines opened on fault current. High winds had damaged the transmission towers approximately 16 miles away from ANO and caused phase to ground faults. This resulted in a loss of all offsite power lines to the 500kV bus. The autotransformer also locked out as designed when the 500kV transmission lines faulted.

The Reactor Operator initiated a manual reactor trip about 8 seconds after the 500kV lines tripped and prior to the reactor protection system initiating an automatic trip. During this time both emergency diesel generators (EDGs) (EK) started as expected. EDG #2 re-energized one Engineered Safeguards bus. EDG #1 ran unloaded until shutdown.

The plant was stabilized in Mode 3 with Emergency Feedwater (EFW) pumps supplying the steam generators, maintaining the water level at the natural circulation setpoint.

At 2155 hours Eastern Daylight Time on 4/3/2017 with the plant in Mode 3 at zero percent power, H. B. Rob.nson Steam Electric Plant, Unit No. 2 (FIBRSEP2), experienced an actuation of the Auxiliary Feedwater (AFW) System during turbine trip logic surveillance testing.

Subsequent investigation determined that the surveillance test was performed without verifying AFW actuation signals were defeated, as required by the test procedure. During performance of the test the AFW system actuated when the only running main feedwater (MFW) pump was tripped as part of the test. Since the AFW defeat switches were not in the defeat position, the AFW system actuated as designed in response to the tripped MFW pump. Main feedwater was restored and the AFW pumps were secured.

The direct cause of the AFW system actuation was inadequate procedure adherence during turbine trip surveillance testing.

On March 20, 2017 at 0813 Eastern Daylight Time (EDT), Watts Bar Nuclear Plant (WBN) Unit 2 operations personnel manually tripped the plant from approximately 91 percent power based on lowering steam generator levels. Prior to the plant trip, the 2A Hotwell pump tripped at 0759 EDT and the 2C Condensate Booster Pump subsequently tripped at 0803 EDT. Operations personnel commenced to lower plant power after the 2A Hotwell pump trip in an attempt to maintain steam generator levels, but were unable to recover level and manually tripped the unit.

All control rods fully inserted and all automatically actuated safety related equipment operated as designed. At 0905 EDT, operations personnel exited the emergency operating instructions after the plant was stabilized.

This event resulted when scaffold crews inadvertently depressed the local trip button for the 2A Hotwell pump, which resulted in the secondary system transient. Bump guard covers were subsequently installed on local pushbuttons for selected pumps in the turbine building.

NRC I ORM TEE :36'01 APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/3112018 comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to NEOB-10202. (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

On March 7, 2016, while performing set-up activities for 2-PT-R084C, "23 EDG 8 Hour Load Test," the normal supply breaker to 480 Volt AC Bus (ED) 3A tripped on overcurrent. This caused 480 Volt AC Buses 3A and 6A to de-energize since, as part of the test set-up activities, the tie breaker (3AT6A) between Buses 3A and 6A was closed and the normal supply breaker for Bus 6A was opened. This resulted in a loss of both 21 and 22 Residual Heat Removal (RHR) (BP) pumps. As 'designed, all Emergency Diesel Generators (EDGs) (EK) received automatic initiation signals to start. All required 480 Volt AC buses automatically re-energized by design, with the exception of Bus 3A, which had an overcurrent lockout. Operators manually started 22 RHR pump to restore RHR cooling.

However, prior to restoring the normal supply power to Bus 3A, 23 EDG tripped on overcurrent which resulted in a second loss of RIM event. The cause for the Bus 3A supply breaker tripping was inadequate procedural guidance resulting in excessive loads being energized on Buses 3A and 6A. The direct cause for 23 EDG tripping was cracked solder joints on the automatic voltage regulator (AVR). Corrective actions included revising 2-PT-R084C and replacing the voltage regulator. The event had no effect on public health and safety.