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At approximately 1500 hours on August 31, 2016, the 21 Reactor Coolant Pump (RCP) tripped resulting in an automatic reactor trip on low flow in one reactor coolant loop above the P-8 permissive (36% power permissive). As expected, the 21, 22 and 23 Auxiliary Feedwater (AFW) pumps started on low steam generator level following the unit trip. Unit 2 was stabilized in Mode 3 at normal operating temperature and pressure with the 22, 23 and 24 RCPs in-service.

The trip of the 21 RCP was caused by a Service Water (SW) leak that developed on the 22 Containment Fan Coil Unit (CFCU) motor cooler. The SW leaked on to the 21 RCP motor lead containment penetration and the motor leads in the termination box. This caused the A and C phase instantaneous overload relays to actuate causing the trip of the RCP and the subsequent reactor trip on low flow in one reactor coolant loop.

This report is being made in accordance with 10CFR50.73 (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)," for this event actuation of the Reactor Protection System (RPS) and the Auxiliary Feedwater System (AF).

On 2/16/16 at 0827 22 Steam Generator Feed Pump (SGFP) tripped while operators were transferring the steam supply to the pump from heating steam to main steam. Trip of 22 SGFP initiated emergency safeguard feature (ESF) actuation for start of the 21 and 22 Auxiliary Feedwater (AFW) Pumps. This event occurred during Unit 2 start-up following a unit trip from generator protection.

This report is being made in accordance with 10CFR50.73 (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)," for this event actuation of the Auxiliary Feedwater System. Notification of this event was provided via ENS report 51738.

TO EPIX

the Desk Officer, Office of Information and Regulatory Affairs, NEOB-1 0202, (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.

1. FACIUTY NAME 2. DOCKET 6. LER NUMBER 3. PAGE Salem Generating Station — Unit 2 05000311

PLANT AND SYSTEM IDENTIFICATION

Westinghouse-Pressurized Water Reactor (PWR/4) Feedwater / Digital Control System (SJ/DCC) *Energy Industry Identification System (EllS) codes and component function identifier codes appear as (SS/CCC).

IDENTIFICATION OF OCCURRENCE

Event Date: 02/16/2016 Discovery Date: 02/16/2016

CONDITIONS PRIOR TO OCCURRENCE

Salem Unit 2 was in Mode 2 (Startup) at 4 percent rated thermal power (RTP).

DESCRIPTION OF OCCURRRENCE

On 2/16/16 at 0827 22 Steam Generator Feed Pump (SGFP) tripped while operators were transferring the steam supply to the pump from heating steam to main steam. Trip of 22 SGFP initiated emergency safeguard feature (ESF) actuation for start of the 21 and 22 Auxiliary Feedwater (AFW) Pumps. This event occurred during Unit 2 start-up following a unit trip from generator protection.

The digital feedwater control system (DFCS) (SJ/DCC) indicated a trip on overspeed. Review of the Plant Computer and the Control Console did not indicate an overspeed trip.

SGFP speed lowered during the swap from heating steam to main steam. SGFP condensate flow momentarily decreased, causing an increase in steam demand to 22 SGFP. At 08:27:17 22 SGFP speed rapidly increased from 2170 to 2450 RPM. The sudden increase in SGFP speed appears to be coincident with opening of the poppet valve, allowing a sudden increase in steam supply to 22 SGFP. Data downloaded from the digital feedwater control system showed a 400 RPM speed increase occurred in 300 milliseconds with all three speed pick up relays indicating a overspeed rate change trip (SGFP acceleration rate trip). 22 SGFP speed slows from 2450 to feedwater control system. No other spikes in SGFP speed were observed in the digital feedwater control system, the Plant Computer or on the associated Control Console during this event.

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.

Salem Generating Station - Unit 2 05000311 The DFCS design change package (DCP) was implemented during the Fall 2015 refueling outage. The rate trip is a new trip added during the DFCS DCP. The SGFP acceleration rate trip is incorporated as standard protection as part of the DFCS speed detection module. The setting is currently at maximum value allowed by the module. This trip is anticipatory to an overspeed condition.

This report is being made in accordance with 10CFR50.73 (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)," for this event actuation of the Auxiliary Feedwater System. Notification of this event was provided via ENS report 51738.

CAUSE OF EVENT

The 22 SGFP trip was a rate trip (-400 RPM increase in 300milliseconds) caused when the main steam poppet valve opened. A root cause evaluation was conducted for this event.

The evaluation determined that one root cause was that the specification agreed upon by PSEG and the DFCS vendor did not identify the acceleration rate trip that was incorporated into the digital feed modification. An independent Critical Digital Review (CDR) was performed by an experienced independent vendor. The CDR did not identify the installation of the trip. The vendor was involved in the process throughout the entire lifecycle, from requirements definition to factory acceptance testing. The design requirements/specifications as defined by PSEG for the implementation of the modification did not identify the acceleration rate trip. The DFCS vendor was contacted and requested to validate that the acceleration rate trip was not discussed in the Functional requirements document.

The response to the inquiry was 'The Trip on acceleration is NOT required; therefore it is not contained in the Functional Requirements Document" The trip function was installed without knowledge by engineering and the vendor had documentation identifying function/trip did exist, but did not specifically communicate the existence or functionality of the specific trip function. The acceleration rate trip will be removed from the system in accordance with the design change process.

A second root cause identified was that the instructions for swapping from low pressure steam to high pressure steam provided in the procedure utilized did not include a conservative description/method for implementing a change in steam supply source to minimize speed perturbation. A review of data collected from the event was performed. The speed and demand signals specific to this event indicated a delta from previous start ups and a speed perturbation was experienced. The feed pump operation was performed within the requirements of the procedure and the review performed by this evaluation indicates that this was not the conservative method to operate/perform the transition from heating steam (HS) to main steam (MS).

Additional guidance is required to prevent further speed perturbations.

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.

Salem Generating Station — Unit 2 05000311

SAFETY CONSEQUENCES AND IMPLICATIONS

There were no safety consequences as a result of this event.

The operating crew responded correctly to the event. The applicable abnormal operating procedure was properly entered and documentation met expectations.

The DFCS and the AFW systems operated as designed. There were no nuclear safety implications associated with this event.

SAFETY SYSTEM FUNCTIONAL FAILURE

This condition did not result a safety system functional failure as defined in NEI 99-02, Regulatory Assessment Performance Indicator Guidelines.

PREVIOUS EVENTS

A review of the previous three years identified no similar events:

CORRECTIVE ACTIONS

• Revise the Material, Equipment and Service Specification governing procedure to require any exceptions or additional features from PSEG detailed specifications be identified by supplier in writing and evaluated by PSEG to determine suitability for use.

• Revise procedure for swapping the SGFPs from low pressure steam to high pressure steam to include guidance for conservative operation during swap from Heating Steam to Main Steam of the SGFP.

COMMITMENTS

There are no regulatory commitments contained in this LER.

On 2/4/16 at 11:21, Salem Unit 2 automatically tripped from approximately 74% power. Power had been reduced at the beginning of dayshift to support a 500 KV transmission line outage. The reactor trip was due to a Main Turbine trip caused by a Main Generator Protection signal initiated by a main generator automatic voltage regulator (AVR) volts/hertz over excitation protection relay. All emergency core cooling systems and emergency safeguards feature systems functioned as expected. As found calibration data for the generator protection logic relay were found out of specification low. An evaluation determined the cause of the generator protection relay trip was poor manufacturing quality and/or shipping damage to an adjusting rheostat.

This report is being made in accordance with 10 CFR 50.73 (aX2Xiv)(A), "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)," specifically automatic actuation of the Reactor Protection System and the Auxiliary Feedwater System for this event.

At 2136 on November 23, 2015, the Boron Injection Tank (BIT) relief valve 2SJ10 exhibited increased seat leakage during the performance of troubleshooting to determine the cause of low BIT pressure. The increased seat leakage from 2SJ10 initiated a Reactor Coolant System (RCS) leak greater than 10 gallons per minute (gpm). Technical Specification (TS) 3.4.7.2.b action b was entered for RCS unidentified leakage greater than 1 gpm.

The BIT was isolated at 2137 and the leakage was stopped. Isolation of the BIT resulted in loss of the high head safety injection flow path for both trains of high head safety injection, requiring entry into TS 3.0.3.

This event was caused by ineffective use of internal operating experience in the decision making process to reuse the 2CV141, which had been installed on the discharge of the 23 positive displacement charging pump, as a suitable replacement for the 2SJ10 during 2R21.

This report is being made in accordance with 10CFR50.73 (a)(2)(v)(D) "Any event or condition that could have prevented the fulfillment of the safety functions of structures or systems that are needed to mitigate the consequences of an accident"

On 1/20/15, a step change occurred on the high differential band indicator of the Axial Flux Difference recorder. Subsequent troubleshooting of the recorder on 1/26/15 identified a failed isolator that provides input to Channel 4 of Overtemperature Delta -T logic circuitry. This failure rendered Channel 4 of the Overtemperature Delta-T protection circuit inoperable for a period of approximately five and a half days without being placed in a tripped condition. The isolator was replaced and the Overtemperature Delta-T Channel was returned to service.

This report is made in accordance with 10 CFR 50.73 (a)(2)(i)(B), "Any operation or condition which was prohibited by the plant's Technical Specifications...

This report is being made in accordance with 10CFR50.73 (a)(2)(i)(A) "The completion of any nuclear plant shutdown required by the plant's Technical Specification.

At 2038 on July 14, 2011, during the performance of the Salem Unit 2 Emergency Core Cooling System (ECCS) fill and vent monthly surveillance test, a leakage path was identified from the Boron Injection Tank (BIT) relief valve 2SJ10 piping. Investigation determined that the leakage was approximately 15 gpm due to lifting of the 2SJ10 relief valve. Upon closure of the BIT inlet valve 2SJ4 to isolate the flow through the relief valve, a through wall socket weld crack developed on the 2SJ10 relief valve inlet piping. The BIT is part of the flow path of the high head safety injection system. Without the high head safety injection flow path operable, Technical Specification (TS) 3.0.3 was entered.

The 2SJ10 relief valve lifting was the result of missed opportunities to correct a component design application deficiency. The socket weld cracking was determined by laboratory analysis to be caused by a combination of fatigue and transgranular stress corrosion cracking. The affected 2SJ10 piping has been replaced with a new straight run of pipe and the relief valve internals were replaced. Design changes will be performed to resolve 1/2SJ10 operating margin, eliminate unnecessary non-isolatable socket welds in the BIT system and replace the remaining non-isolatable socket welds in the BIT system with low carbon weld filler and install a stiffener on the 2SJ10 relief valve piping.

Salem Generating Station Unit 2 05000311

This report is being made in accordance with 10CFR50.73 (a)(2)(i)(B), "any operation or condition which was prohibited by the plant's Technical Specifications...

On April 11, 2011, at 11: 51 control room personnel entered TS 3.4.10.3 Act b to support testing of the Pressurizer Overpressure Protection System (POPS) channel 1 (2PR1) in accordance with procedure S2.OP- ST.PZR-0003 "Inservice Testing Pressurizer and Reactor Head Vent Valves." When the 2PR1 valve was demanded to open as the test key switch was turned to the test position, the channel 1 test light illuminated, but the valve did not respond as expected. 2PR1 was restored to its pretest position; however, 2PR1 remained inoperable and OFF. Following satisfactorily testing of 2PR2, control room personnel attempted to open 2PR1 from normal control room bezel, but 2PR1 failed to open again. At this point it was determined that 2PR1 had been inoperable since the entry into Mode 5 on April 10 at 02:21, and that Salem Unit 2 had operated in a condition prohibited by Technical Specifications. The troubleshooting and the as-found condition of the valve plug OD & cage ID confirmed that foreign material was the most likely cause of the failure of the valve to open upon initial demand. A new trim set was installed into the valve, and the valve was tested satisfactorily.

Salem Generating Station Unit 2 05000311

On January 21, 2010, at 1818 hours, the 21 Steam Generator Feedwater Pump (SGFP) tripped. A turbine .

runback automatically initiated as expected and steam generator level in all four Steam Generators (SG) continued to lower. The 22 SG reached the SG low level reactor trip setpoint at 1820 hours resulting in an automatic reactor trip. All control rods fully inserted on the trip. All three Auxiliary Feedwater (AFW) pumps started in response to the low SG water level and decay heat was removed by the steam dumps to the main condenser. Operators entered the emergency procedures for the plant trip and stabilized the plant in Mode 3 (HOT STANDBY).

The cause of the 21 SGFP trip was an internal wiring short in the SGFP trip control circuit that resulted in a false low suction pressure trip signal. The cause for the wiring short was the result of poor work practices. The reactor tripped on low water level in the 22 SG as designed. Corrective actions consist of lug inspections, document changes, training analysis, and evaluation of the integrated plant response to a SGFP trip from full power and implementing changes as appropriate.

This report is made in accordance with 10CFR50.73 (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).

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