IR 05000272/2020003

Integrated Inspection Report 05000272/2020003 and 05000311/2020003

ML20314A149
Person / Time
Site:	Salem
Issue date:	11/09/2020
From:	Brice Bickett Reactor Projects Branch 3
To:	Carr E Public Service Enterprise Group
Bickett B
References
IR 2020003
Download: ML20314A149 (21)

Text

November 9, 2020

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNITS 1 AND 2 - INTEGRATED INSPECTION REPORT 05000272/2020003 AND 05000311/2020003

Dear Mr. Carr:

On September 30, 2020, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Salem Nuclear Generating Station Units 1 and 2. On October 1, 2020, the NRC inspectors discussed the results of this inspection with Mr. Dave Sharbaugh, Plant Manager and other members of your staff. The results of this inspection are documented in the enclosed report.

Two findings of very low safety significance (Green) are documented in this report. One of these findings involved a violation of NRC requirements. We are treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violation or the significance or severity of the violation documented in this inspection report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement; and the NRC Resident Inspector at Salem Nuclear Generating Station, Units 1 and 2.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; and the NRC Resident Inspector at Salem Nuclear Generating Station, Units 1 and 2. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, X /RA/

Signed by: Brice A. Bickett Brice A. Bickett, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket Nos. 05000272 and 05000311 License Nos. DPR-70 and DPR-75

Enclosure:

As stated

Inspection Report

Docket Numbers: 05000272 and 05000311 License Numbers: DPR-70 and DPR-75 Report Numbers: 05000272/2020003 and 05000311/2020003 Enterprise Identifier: I-2020-003-0018 Licensee: PSEG Nuclear, LLC Facility: Salem Nuclear Generating Station, Units 1 and 2 Location: Hancocks Bridge, NJ 08038 Inspection Dates: July 1, 2020 to September 30, 2020 Inspectors: J. Hawkins, Senior Resident Inspector M. Hardgrove, Resident Inspector P. Finney, Senior Project Engineer R. Rolph, Resident Inspector S. Wilson, Senior Health Physicist Approved By: Brice A. Bickett, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an integrated inspection at Salem Nuclear Generating Station,

Units 1 and 2, in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information.

List of Findings and Violations

Foreign Material Exclusion Program Procedures Not Followed during Unit 2 Refueling Outage Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green None (NPP) 71152 FIN 05000311/2020003-01 Open/Closed A Green self-revealing finding was identified because PSEG did not follow their Foreign Material Exclusion Program procedure, MA-AA-716-008, for all missing feedwater heater tube plugs between April 18, 2011, and May 14, 2020. Specifically, PSEG identified the missing tube plugs in 2011, however, ER-AA-2006, Lost Parts Evaluations, was not performed for the missing tube plugs and the required recovery plan was not initiated as required per MA-AA-716-008. As a result, the 24BF19 steam generator (SG) feedwater regulating valve (FRV) became mechanically restricted, unable to open or close, due to a missing tube plug, which resulted in PSEG being unable to continue with an in-progress power ascension on Unit 2 and an abnormal lineup controlling steam generator water level during a down power and shutdown in order to repair the valve.

Inadequate Preventive Maintenance of the Unit 2 23 Turbine Driven Auxiliary Feedwater Pump Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.6] - Design 71152 Systems NCV 05000311/2020003-02 Margins Open/Closed A self-revealing Green finding and associated non-cited violation (NCV) of Technical Specification 6.8.1, Procedures and Programs, when PSEG did not properly preplan documented instructions appropriate to the circumstances for the flushing and replacement of oil in the turbine driven auxiliary feedwater (TDAFW) pump governor. Specifically, PSEGs preventive maintenance (PM) procedure, S2.IC-ZZ.AF-0018, Revision 10, did not include actions to periodically perform dynamic flushing and replacement of the TDAFW pump governor oil and did not instruct operators to use a 5 micron filter when adding oil to the system. Consequently, on May 9, 2020, the 23 TDAFW pump exhibited excessive speed oscillations, governor hunting, and the lifting of two system relief valves, which resulted in an entry into a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> shutdown Technical Specification Action Statement (TSAS) during inservice testing while in Mode 3, and an elevation in plant monitored shutdown risk.

Additional Tracking Items

None.

PLANT STATUS

Unit 1 began the inspection period at rated thermal power. The unit remained at or near rated thermal power for the remainder of the inspection period.

Unit 2 began the inspection period at rated thermal power. On August 5, 2020, the unit was down powered to 90 percent due to an equipment failure that affected condenser vacuum. The unit was returned to rated thermal power later that same day and remained at or near rated thermal power for the remainder of the inspection period.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

Starting on March 20, 2020, in response to the National Emergency declared by the President of the United States on the public health risks of the coronavirus (COVID-19), resident and regional inspectors were directed to begin telework and to remotely access licensee information using available technology. During this time the resident inspectors performed periodic site visits each week, increasing the amount of time on site as local COVID-19 conditions permitted. As part of their onsite activities, resident inspectors conducted plant status activities as described in IMC 2515, Appendix D; observed risk significant activities; and completed on site portions of IPs. In addition, resident and regional baseline inspections were evaluated to determine if all or portion of the objectives and requirements stated in the IP could be performed remotely. If the inspections could be performed remotely, they were conducted per the applicable IP. In some cases, portions of an IP were completed remotely and on site. The inspections documented below met the objectives and requirements for completion of the IP.

71111.01 - Adverse Weather Protection

Impending Severe Weather Sample (IP Section 03.02) (1 Sample)

(1) Severe weather warning and thunderstorms on July 6

71111.04 - Equipment Alignment

Partial Walkdown Sample (IP Section 03.01) (4 Samples)

The inspectors evaluated system configurations during partial walkdowns of the following systems/trains:

(1) Unit 2, 24 station power transformer (SPT) due to carbon monoxide alarm and oil leak during the week of July 13

(2) Unit 2, 23 heater drain pump discharge flange steam leak during the week of September 14

(3) Unit 2, 2B and 2C emergency diesel generators while testing the 2A during the week of September 28

(4) Common, Salem gas turbine failure to start and run during the week of September 14

71111.05 - Fire Protection

Fire Area Walkdown and Inspection Sample (IP Section 03.01) (6 Samples)

The inspectors evaluated the implementation of the fire protection program by conducting a walkdown and performing a review to verify program compliance, equipment functionality, material condition, and operational readiness of the following fire areas:

(1) Unit 1, turbine generator fire plan during preparations for 1R27 outage the week of September 21

(2) Unit 2, service water intake structure during inservice testing of 21 service water pump during the week of July 27

(3) Unit 2, 2C emergency diesel generator room due to the entry door broken latch requiring an hourly fire watch during the week of August 7

(4) Unit 2, auxiliary building fire detector failed during testing and required an hourly fire watch during the week of August 17

(5) Unit 2, turbine generator fire plan following steam leak repairs the week of September 21

(6) Unit 2, 2A emergency diesel generator room and control area during the week of

September 28 Fire Brigade Drill Performance Sample (IP Section 03.02) (1 Sample)

(1) Unit 1, fire drill tabletop and brigade training for a simulated fire in the service water bay for the 11, 12, and 13 pump room during week of September 7

71111.11Q - Licensed Operator Requalification Program and Licensed Operator Performance

Licensed Operator Requalification Training/Examinations (IP Section 03.02) (1 Sample)

(1) Observed licensed operator performance during a training scenario in the Salem simulator on September 1 and 2

71111.12 - Maintenance Effectiveness

Maintenance Effectiveness (IP Section 03.01) (2 Samples)

The inspectors evaluated the effectiveness of maintenance to ensure the following structures, systems, and components (SSCs) remain capable of performing their intended function:

(1) Unit 2, 24 feedwater regulating valve (24BF19) maintenance rule functional failure and tracking during the week of August 12

(2) Unit 2, 22B emergency diesel generator service air compressor degraded oil during the week of August 31

Quality Control (IP Section 03.02) (1 Sample)

The inspectors evaluated the effectiveness of maintenance and quality control activities to ensure the following SSC remains capable of performing its intended function:

(1) Unit 1 and 2, review of the rod control Solatron transformer capacitors during the week of September 14

71111.13 - Maintenance Risk Assessments and Emergent Work Control

Risk Assessment and Management Sample (IP Section 03.01) (4 Samples)

The inspectors evaluated the accuracy and completeness of risk assessments for the following planned and emergent work activities to ensure configuration changes and appropriate work controls were addressed;

(1) Common, planned emergency diesel generator testing during a severe thunderstorm warning (PRA yellow) on July 6

(2) Unit 1, protected equipment and fire in (a)(4) risk management actions for planned 11 Residual Heat Removal pump maintenance on August 24

(3) Unit 1, solid state protection system (SSPS) disagreement between Train A and B, troubleshooting and resolution during the week of August 24

(4) Unit 2, 22 residual heat removal pump surveillance testing during a National Weather Service severe thunderstorm warning and elevated risk on August 7

71111.15 - Operability Determinations and Functionality Assessments

Operability Determination or Functionality Assessment (IP Section 03.01) (3 Samples)

The inspectors evaluated the licensee's justifications and actions associated with the following operability determinations and functionality assessments:

(1) Unit 1, review of operability evaluation (OPEVAL) 20-12 for individual rod position indication (IRPI) degradation due to a faulty power transformer during the week of July 6-10

(2) Unit 2, 21 steam generator feed pump recirculation valve (21BF32) steam leak during the week of July 27

(3) Unit 1 and Unit 2, containment high range radiation monitors 10 CFR Part 21 evaluation for untapped screw holes during week of July 27

71111.18 - Plant Modifications

Temporary Modifications and/or Permanent Modifications (IP Section 03.01 and/or 03.02)

(1 Sample)

The inspectors evaluated the following temporary or permanent modifications:

(1) Unit 1, 12 reactor coolant pump breaker temporary modification for SSPS lifted lead due to unexpected voltage during troubleshooting during the week of August 31

71111.19 - Post-Maintenance Testing

Post-Maintenance Test Sample (IP Section 03.01) (4 Samples)

The inspectors evaluated the following post maintenance test activities to verify system operability and functionality:

(1) Unit 1, 1C emergency diesel generator unloaded run and relay chattering troubleshooting during the week of July 27

(2) Unit 2, 24 containment fan cooling unit (CFCU) service water outlet valve (24SW76)actuator repair during the week of July 13

(3) Unit 2, 2C emergency diesel generator unloaded run utilizing the 22A starting air compressor after water intrusion into the oil during the week of August 12

(4) Unit 2, main bus duct cooling fan vibration investigation and repair following down power to 55 percent reactor power during the week of August 31

71111.22 - Surveillance Testing

The inspectors evaluated the following surveillance tests:

Surveillance Tests (other) (IP Section 03.01)

(1) Unit 1, 1A emergency diesel generator monthly surveillance test conducted during the week of September 28

(2) Unit 1, 1A emergency diesel generator 24-hour endurance run surveillance test during the week of September 28

(3) Unit 2, 2B emergency diesel generator (EDG) surveillance testing using the train 'B' starting air test during the week of July 6-10

(4) Unit 2, 23 auxiliary feedwater pump surveillance test during the week of September 7

(5) Unit 1 and 2, review of the FLEX diesel generator engine control module testing during the week of September 14

Inservice Testing (IP Section 03.01) (3 Samples)

(1) Unit 1, 11 auxiliary feedwater pump inservice testing following hydraulic governor calibration during the week of July 27

(2) Unit 2, 25 service water pump inservice testing during the week of July 13

(3) Unit 2, 2PR6 and 2PR7 pressurizer block valve inservice testing during the week of July

71124.01 - Radiological Hazard Assessment and Exposure Controls

Radiological Hazard Assessment (IP Section 03.01) (1 Sample)

(1) The inspectors evaluated how the licensee identifies the magnitude and extent of radiation levels and the concentrations and quantities of radioactive materials and how the licensee assesses radiological hazards.

Instructions to Workers (IP Section 03.02) (1 Sample)

(1) The inspectors evaluated radiological protection-related instructions to plant workers. Specifically, inspectors reviewed radiation work permit number 24 and ALARA Plan number 58 for Unit 2 regenerative heat exchanger maintenance.

Contamination and Radioactive Material Control (IP Section 03.03) (2 Samples)

The inspectors evaluated licensee processes for monitoring and controlling contamination and radioactive material.

(1) Observed licensee surveys of potentially contaminated material leaving the RCA at main control point exit

(2) Observed all site radioactive material storage areas

Radiological Hazards Control and Work Coverage (IP Section 03.04) (2 Samples)

The inspectors evaluated in-plant radiological conditions during facility walkdowns and observation of radiological work activities.

(1) Observed workers performing functional check on Unit 1 radwaste effluent monitor

==1R18

(2) Observed the licensees control of highly radioactive items stored in Unit 1 and 2 ==

spent fuel pools.

High Radiation Area and Very High Radiation Area Controls (IP Section 03.05) (1 Sample)

The inspectors evaluated licensee controls of the following High Radiation Areas and Very High Radiation Areas:

(1) Unit 1 and Unit 2 containment access Radiation Worker Performance and Radiation Protection Technician Proficiency (IP Section 03.06) (1 Sample)

(1) The inspectors evaluated radiation worker and radiation protection technician performance as it pertains to radiation protection requirements.

71124.05 - Radiation Monitoring Instrumentation

Walkdowns and Observations (IP Section 03.01) (10 Samples)

The inspectors evaluated the following radiation detection instrumentation during plant walkdowns:

(1) Portable ion chambers stored ready for use' at the entrance to the radiologically controlled area:

Ludlum model 9 number 316410 Ludlum model 9 number 316430 Ludlum model 9 number 316357 Ludlum model 9 number 316416

(2) Telepole instruments stored ready for use at the entrance to the radiologically controlled area:

6610-074 6613-030

(3) Personnel contamination monitors at the exit to the radiologically controlled area:

Argos number 1412-575 Argos number 1412-288

(4) AMS-4 area airborne monitors:

S12926 Unit 1 fuel storage building S12928 Unit 1 auxiliary building 84' elevation

Calibration and Testing Program (IP Section 03.02) (15 Samples)

The inspectors evaluated the calibration and testing of the following radiation detection instruments:

Containment High Range Area Monitor 1R44A 1RA2584 Containment High Range Area Monitor 2R44B 2RA2586 Spent Fuel Handling Crane Area 1R32A 1RA8350 Control Room Area Monitor 2R1A 2RA16336K Spent Fuel Handling Crane Area 2R32A 2RA8350 Fastscan whole body counter located in the PSEG Processing Center Eberline RM14 number H6092 Ludlum 2360 number S312718 Ludlum 2360 number S312728 Ludlum 9 number H316383 Ludlum 9 number S316388 Eberline E520 number S1175 Mirion telepole number S6610-023 Mirion telepole number S6610-064 Effluent Monitoring Calibration and Testing Program Sample (IP Sample 03.03) (2 Samples)

The inspectors evaluated the calibration and maintenance of the following radioactive effluent monitoring and measurement instrumentation:

(1) Unit 1, liquid radioactive waste effluent monitor number 1R18

(2) Unit 1, south plant vent stack radiation monitoring system noble gas high channel 4875C1

OTHER ACTIVITIES - BASELINE

===71151 - Performance Indicator Verification The inspectors verified licensee performance indicators submittals listed below:

MS07: High Pressure Injection Systems (IP Section 02.06) ===

(1) Unit 1, July 1, 2019 - June 30, 2020

(2) Unit 2, July 1, 2019 - June 30, 2020

MS08: Heat Removal Systems (IP Section 02.07) (2 Samples)

(1) Unit 1, July 1, 2019 - June 30, 2020

(2) Unit 2, July 1, 2019 - June 30, 2020

MS09: Residual Heat Removal Systems (IP Section 02.08) (2 Samples)

(1) Unit 1, July 1, 2019 - June 30, 2020

(2) Unit 2, July 1, 2019 - June 30, 2020

71152 - Problem Identification and Resolution

Annual Follow-up of Selected Issues (IP Section 02.03) (2 Samples)

The inspectors reviewed the licensees implementation of its corrective action program related to the following issues:

(1) Unit 1, review of an individual rod position indication transformer failure that resulted in entry into an unplanned 24-hour Technical Specification Action Statement during the week of August 31

(2) Unit 2, review of 23 turbine driven auxiliary feedwater (TDAFW) pump inoperability during the week of August 17

71153 - Followup of Events and Notices of Enforcement Discretion Event Followup (IP Section 03.01)

(1) Review of Licensee Event Report 2020-002-00 for Salem Unit 1 and Unit 2 RHR availability for Emergency Core Cooling in Mode 4 during the week of September

INSPECTION RESULTS

Foreign Material Exclusion Program Procedures Not Followed during Unit 2 Refueling Outage Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green None (NPP) 71152 FIN 05000311/2020003-01 Open/Closed A Green self-revealing finding was identified because PSEG did not follow their Foreign Material Exclusion Program procedure, MA-AA-716-008, for all missing feedwater heater tube plugs between April 18, 2011, and May 14, 2020. Specifically, PSEG identified the missing tube plugs in 2011, however, ER-AA-2006, Lost Parts Evaluations, was not performed for the missing tube plugs and the required recovery plan was not initiated as required per MA-AA-716-008. As a result, the 24BF19 steam generator (SG) feedwater regulating valve (FRV) became mechanically restricted, unable to open or close, due to a missing tube plug, which resulted in PSEG being unable to continue with an in-progress power ascension on Unit 2 and an abnormal lineup controlling steam generator water level during a down power and shutdown in order to repair the valve.

Description:

At Salem, the FRVs are required to throttle flow into the secondary sides of the SGs in response to SG water level and feedwater flow signals. These valves are designed to take this input and automatically throttle open or closed depending on demand. Position feedback is accomplished through linkage from the actuator stem rod to a lever attached to the shaft assembly with a magnet that provides input to the positioner.

On May 14, 2020, during power ascension at 73 percent reactor power, following the completion of the Unit 2 refuel outage, operators stopped the power ascension due to an unexpected and improper equipment response from the 24BF19, one of the four Unit 2 SG FRVs. Operators in the main control room received an overhead alarm (OHA) indicating trouble with the advanced digital feedwater control system (ADFCS) due to a mismatch between the 24BF19 valve demand and system setpoint. After stopping the power ascension and investigating the alarm, operators determined that the 24BF19 was mechanically stuck at approximately 50 percent open. Operators immediately placed the 24BF19 in manual, raised the 24 steam generator blowdown (SGBD) to maximum, and controlled 24 SG water level (SGWL) using the 24 SG FRV bypass valve, 24BF40. Technical Specification 3.7.13, action B was entered at 0345, and following simple troubleshooting activities to understand the failure, PSEG determined a controlled shutdown was required to make the needed repairs to the 24BF19. PSEG operations and engineering personnel had to develop a viable and safe strategy for performing the controlled shutdown utilizing the simulator as this lineup while shutting down the unit was not in existing operations procedures. PSEGs multiple simulator runs proved that the appropriate strategy to ensure safe operator performance during the required controlled shutdown was to use a dedicated control room operator and supervisor to manually control SGWL using the 21 SG feed pump speed control and by limiting shutdown activities to removing activities usually done in parallel (removal of condensate pumps, heater drain pumps, condensate polisher beds, and feed pumps) so as to minimize large fluctuations in SGWL that the dedicated operator would not be able to keep up with, avoiding either a high or low SGWL and the potential automatic trip of the unit.

Control room operators completed the controlled shutdown of Unit 2 and upon disassembly of 24BF19 valve, a feedwater heater tube plug was found lodged in the valve cage restricting the valves movement.

PSEG repaired the 24BF19 and completed a causal evaluation (70213234) which determined that the plug found in the 24BF19 was at least 5 years old, based on a lack of laser markings, and that the required lost parts evaluations and recovery plans had not been initiated for all legacy missing outlet plugs or missing inlet plugs. PSEG identified that on April 18, 2011, during a Unit 2 refueling outage, foreign material (missing feedwater heater tube plugs) was removed from the steam generator secondary side loose part trapping screens as documented in NOTF 20506156. PSEG noted that a technical evaluation was performed in accordance with CC-AA-309-101, Engineering Technical Evaluations, which identified that the 26A feedwater heater tube plug mapping contained discrepancies. Specifically, these discrepancies included a total of 10 inlet and 4 outlet tube plugs missing and six plugs installed in the wrong tubes. Although this information was identified and documented in the technical evaluation, PSEGs causal evaluation found that a lost parts evaluation had not been performed as required by ER-AA-2006, Section 4.2.4 and Attachments 10, Loss of Integrity Notification and Recovery Plan, and a recovery plan had not been initiated as required by MA-AA-716-008, Section 4.3.5.5 and Attachment 9, Loss of Integrity Actions. As part of PSEGs extent of condition for other potentially missing feedwater heater tube plugs, the 26B feedwater heater was inspected for missing plugs but no missing plugs were identified. The 26A and 26C feedwater heaters were not checked because their plugs had been checked for tightness and their tube map validated during 2R24.

Based on the information above, the inspectors determined that PSEG did not follow their Foreign Material Exclusion Program procedure, MA-AA-716-008, for all missing feedwater heater tube plugs between April 18, 2011 and May 14, 2020.

Corrective Actions: PSEGs corrective actions included repairing the 24BF19, performing an extent of condition involving inspections and tube mapping reviews of the 26 feedwater heaters, revising current foreign material procedures with industry, and revising the lost parts evaluation and recovery plan procedures.

Corrective Action References: 70213234

Performance Assessment:

Performance Deficiency: The inspectors determined that PSEG not following the foreign material exclusion program and not performing a lost parts evaluations under ER-AA-2006 and recovery plans for missing feedwater heater tube plugs as required per MA-AA-716-008 was a performance deficiency within PSEGs ability to foresee and correct and which should have been prevented.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Human Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, PSEG not following their procedures for foreign material exclusion, lost parts evaluations, and recovery plans prevented the potential of locating the lost tube plugs and led to the foreign material intrusion of the 24BF19, mechanically restricting the valves movement and resulting in an unplanned unit shutdown.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The finding screened to Green, very low safety significance, since the finding did not cause both a reactor trip and a loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. Specifically, although the 24BF19 was unable to operate as designed and PSEG had to develop viable and safe operating procedures to avoid a high or low SGWL and the potential automatic trip of the unit during a controlled shutdown, PSEG was able to successfully execute the shutdown of the unit safely and without further complication.

Cross-Cutting Aspect: Not Present Performance. No cross-cutting aspect was assigned to this finding because the inspectors determined the finding did not reflect present licensee performance.

Enforcement:

Inspectors did not identify a violation of regulatory requirements associated with this finding.

Inadequate Preventive Maintenance of the Unit 2 23 Turbine Driven Auxiliary Feedwater Pump Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.6] - Design 71152 Systems NCV 05000311/2020003-02 Margins Open/Closed A self-revealing Green finding and associated non-cited violation (NCV) of Technical Specification 6.8.1, Procedures and Programs, when PSEG did not properly preplan documented instructions appropriate to the circumstances for the flushing and replacement of oil in the turbine driven auxiliary feedwater (TDAFW) pump governor. Specifically, PSEGs preventive maintenance (PM) procedure, S2.IC-ZZ.AF-0018, Rev 10, did not include actions to periodically perform dynamic flushing and replacement of the TDAFW pump governor oil and did not instruct operators to use a 5 micron filter when adding oil to the system.

Consequently, on May 9, 2020, the 23 TDAFW pump exhibited excessive speed oscillations, governor hunting, and the lifting of two system relief valves, which resulted in an entry into a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> shutdown Technical Specification Action Statement (TSAS) during inservice testing while in Mode 3, and an elevation in plant monitored shutdown risk.

Description:

The auxiliary feedwater (AFW) system serves as a backup system for supplying feedwater to the secondary side of the steam generators when the main feedwater system is not available. The AFW system is relied upon for extended periods to prevent core damage and system over pressurization in the event of accidents such as a loss of normal feedwater or a secondary system pipe rupture, and to provide a means for plant cooldown. The 23 TDAFW pump is steam driven and its governor and bearing oil is cooled through coolers via a minimum flow recirculation line. PSEG is required to perform quarterly surveillance testing of the 23 TDAFW pump to ensure its operability. The 23 TDAFW pump uses a Woodward PG-PL type mechanical governor. Steam is emitted to the 23 TDAFW pump through the 2MS52, turbine trip valve, and throttled by 2MS53, turbine governor valve. The steam spins and drives the turbine, which drives the 23 AFW pump governor, which receives power and turbine speed feedback input from the turbines shaft.

On May 9, 2020, during performance of the 23 TDAFW pump inservice testing (S2.OP-ST.AF-0003), to support post maintenance testing (PMT) activities, the pump speed began to oscillate in excess of 1000 rpm (NOTF 20852682). Two of the relief valves in the system, 2MS51, the main steam and turbine bypass safety relief valve (SRV), and 2AF128, the pump bearing jacket water cooling outlet SRV, unexpectedly cycled open and closed with the excessive speed oscillations until main control room operators tripped the pump. PSEG immediately secured the pump and declared it inoperable, entered a 72-hour shutdown TSAS, and elevated plant risk due to the equipment failure. PSEG performed complex troubleshooting and a causal evaluation (70213188) which determined that the direct cause of the pump oscillations was degraded governor hydraulic performance due to internal blockage in the governor which impacted its ability to control pump speed and immediately compensate for large speed demand step changes. PSEG cleared the blockage by dynamically flushing the governor with lighter oil (i.e. diesel fuel oil). PSEGs discussions with industry and the governor vendor suggested that the blockage may have been caused by disturbing the governor during maintenance activities during the recent system outage and associated oil change and flushing practices. Per PSEGs causal evaluation (70213188), the cause was not prevented because of the oil change and flushing practices, along with the maintenance procedures performed during 2R24. Oil changes performed during the turbine overhaul were a drain and fill, not a dynamic flush which would have removed the particulates inside the bottom of the governor reservoir.

The inspectors reviewed the event and PSEGs causal evaluation. In addition to the documented issues in Section 71152 of this report, the following was noted by the inspectors during their review:

PSEG has not been using a 5 micron filter for adding or changing oil in the TDAFW governor. The inspectors found that the vendor technical document, 174547, Terry Turbine Manual for AFW Turbine Driven Pump (2019), states that for oil system flushing, Important:

All oil should be filtered through a filter press or through a temporary 5 micron filter before adding it to the system. The industry PM guide for Terry Turbine AFW Application (2002),

TR1007461, states that new oil should be passed through a filter press or nominal 5 micron filter. Additionally, the inspectors noted a number of operating experience events that discussed that history has shown a significant reduction in governor failure when a 5 micron filter is used and to change the oil and flush governor lubricating and lube oil systems at 18 to 24 month intervals or sooner as dictated by sample results.

PSEG has not been performing dynamic flushes of the TDAFW governor oil when it exceeds acceptance criteria. The inspectors found that the industry PM guide states to review the historic and present analysis data for the oil removed from the turbine assembly. If the oil particle count exceeds the acceptance criteria, it is recommended that the turbine oil system be mechanically cleaned or flushed. PSEGs causal evaluation stated that the vendor recommends dynamic draining and flushing of the governor as the most effective method to remove the particulates that accumulate at the bottom of the oil reservoir. The inspectors also noted significant industry operating experiences recommending incorporating dynamic system flushing into the TDAFW PM plan.

PSEG was not performing more frequent inspection and cleaning of the turbine oil system orifices (including the tight clearances of the governor) when there was a documented history of particulate blockage that caused previous failures, including a previous failure of the installed governor on the 23 TDAFW pump. The inspectors found that the industry PM guide states that the oil system orifices should be inspected for accumulation of foreign material and potential blockage of flow during each major turbine inspection cycle (that is, approximately every 6-10 years). This should be done more frequently if there have been problems with high particulate or FM in the oil.

Based on the information above, the inspectors determined that PSEG PM procedure, S2.IC-ZZ.AF-0018, Revision 10, did not include adequate actions to periodically perform dynamic flushing and replacement of the TDAFW pump governor oil and did not instruct operators to use a 5 micron filter when adding oil to the system.

Corrective Actions: PSEGs corrective actions included performing complex troubleshooting, completing a causal evaluation, revising TDAFW pump maintenance procedures, creating new systems to automatically trend oil analysis results, and just-in time training for system engineers and managers. PSEG also revised their procedures to ensure the proper flushing of the governor internals and the appropriate vendor guidance was incorporated.

Corrective Action References: 70213188 and 70213450

Performance Assessment:

Performance Deficiency: PSEG did not properly preplan documented instructions appropriate to the circumstances for the flushing and replacement of oil in the TDAFW pump governor in PM procedure, S2.IC-ZZ.AF-0018, Rev 10, and was a performance deficiency that was reasonably within the licensees ability to foresee and should have been prevented.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Procedure Quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the maintenance procedure did not provide sufficient written instructions to ensure adequate governor oil quality and, thereby, reliable performance of the TDAFW system.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The finding screened to Green, very low safety significance, since all Mitigating Systems Screening questions were answered No.

Cross-Cutting Aspect: H.6 - Design Margins: The organization operates and maintains equipment within design margins. Margins are carefully guarded and changed only through a systematic and rigorous process. Special attention is placed on maintaining fission product barriers, defense-in-depth, and safety related equipment. The inspectors determined that this finding had a cross-cutting aspect in Human Performance, Design Margins, because PSEG did not give special attention to operating and maintaining safety related equipment within design margins, specifically the vendor and industry recommended design margins associated with oil changes, system flushing, and oil analysis.

Enforcement:

Violation: Technical Specification 6.8.1, Procedures and Programs, requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2. Regulatory Guide 1.33, Section 9.a, Procedures for Performing Maintenance, states, in part, that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, or documented instructions, appropriate to the circumstances.

Contrary to the above, PSEG PM procedure S2.IC-ZZ.AF-0018, as well as work order instructions, did not properly preplan documented instructions appropriate to the circumstances for the flushing and replacement of oil in the TDAFW pump governor, from the establishment of the procedures until present. Specifically, S2.IC-ZZ.AF-0018 did not include actions to periodically perform periodic dynamic flushing and replacement of the TDAFW pump governor oil and did not instruct operators to use a 5 micron filter when adding oil to the system. Consequently, on May 9, 2020, the 23 TDAFW pump exhibited excessive speed oscillations and governor hunting, the lifting of two system relief valves, entry into a 72-hour shutdown TSAS during inservice testing while in Mode 3, and required an elevation in plant monitored shutdown risk.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Observation: Unit 2, review of 23 turbine driven auxiliary feedwater (TDAFW) 71152 pump inoperability due to erratic governor speed swings on May 9, 2020 The inspectors reviewed PSEGs recent equipment performance issue with the 23 TDAFW pump during inservice testing on May 9, 2020. During the test, the pumps speed began to oscillate in excess of 1000 revolutions per minute (rpm) and multiple system relief valves lifted unexpectedly. After securing the pump, declaring it inoperable, and troubleshooting the speed oscillations, PSEG determined that degraded governor hydraulic performance due to internal oil particulate blockage caused the erratic pump response.

The inspectors reviewed PSEGs causal evaluation and 23 TDAFW pump governor history, noting the following observations, in addition to the documented performance deficiency in Section 71152 of this report:

1. The 23 TDAFW pump oil wear particle content (WPC) exceeded its procedural limits during consecutive oil samples on December 12, 2019 (112 WPC > Fault limit 80 WPC), March 12, 2020 (85.8 WPC), April 14, 2020 (68 WPC > Alert limit 40 WPC),and May 8, 2020 (100 WPC). PSEGs procedure ER-AA-230-1001, Oil Analysis Interpretation Guideline, documents these limits in Attachment 14 stating that the ALERT limit for WPC is double the baseline value and greater than 40. The FAULT limit is listed as greater than 80. The procedure also states in Section 4.2.3 -

Establishing Oil Analysis Limits, these limits (ALERT and FAULT) should be viewed as action levels with the level of action specific to the degree of the problem; and, in Section 4.3 - Adverse Oil Trend Actions, if a component has exceeded the FAULT (critical threshold) then a notification shall be initiated and that this component would be further classified as ORANGE, or Restricted, requiring emergent scheduling for repair because it is potentially rapidly degrading. No NOTFs or repair work orders were initiated during the time when PSEG exceeded the WPC limits between December 2019 and May 2020, which was not in accordance with their procedure.

2. PSEGs causal evaluation (70213188) did not adequately support its conclusion regarding the potential cause of the high WPC in the governor oil samples.

Specifically, PSEG concluded that a short dwell time was the reason WPC was high between December 2019 and May 2020, stating in their evaluation that a review of the WPC from governor oil sampling concluded that the step change in trend was attributed to how long a sample is drawn after pump run since particulates and wear products will settle over time (short dwell time). The inspectors determined that this conclusion was not supportable by site information. When questioned by the inspectors, PSEG engineering was unable to produce actual times to support this conclusion. This statement went unchallenged by PSEGs management review committee (MRC) when the product was approved.

3. PSEGs evaluation noted that the critical parameters measured of viscosity, water content, and total acid number were within acceptance criteria. Since the governor was replaced in May 2017, there has been no evidence of governor performance issues. The 23 TDAFW governor had previously been installed on the 13 TDAFW pump in 2009 when it failed due to high water content in the oil (~1500 ppm). At the time, PSEG replaced the governor and sent the failed governor out for refurbishment. This previously failed and refurbished governor was then installed on the 23 TDAFW pump in May 2017. PSEGs evaluation did not investigate the vendor refurbishment, procurement, or storage processes which could have contributed to the governor experiencing a similar failure mode after it was installed on the 23 TDAFW pump. This gap went unchallenged and undiscussed by PSEGs MRC when the product was approved.

PSEG entered these observations into their CAP under 20861208. PSEGs corrective actions included performing a station self-assessment (70213450) on the oil analysis, interpretation, and trending program. PSEG also created corrective actions to revise the applicable procedures, implemented a new program to allow for easier and more visible trending of oil analysis results, and provided just-in time training for operators and system engineers.

The inspectors documented a performance deficiency related to this review in Section 71152 of this report. The observations noted above were evaluated to be minor violations in accordance with IMC 0612, Appendix B and Appendix E. Consequently, these issues were not subject to enforcement action in accordance with the NRCs enforcement policy.

Minor Violation 71153 Minor Violation: The inspectors reviewed PSEGs corrective actions regarding an evaluation performed on May 5, 2020, that determined in Mode 4 the temperature of the fluid in the residual heat removal (RHR) pump suction header could exceed the temperature at which, under postulated shutdown loss of coolant accident (LOCA) conditions, could have resulted in cavitation of the RHR system. PSEGs evaluation went on to determine the condition is postulated to occur during both the injection phase, when suction is aligned to the refueling water storage tank (RWST) as well as the recirculation phase when suction is aligned to the Emergency Core Cooling (ECCS) sump. As a result, on July 6, 2020, PSEG submitted LER 2020-002-00 for Salem Unit 1 and Unit 2 RHR Availability for Emergency Core Cooling in Mode 4 as this condition results in the inoperability of the RHR system while in Mode 4. The inspectors reviewed the evaluation and previous industry responses to this potential cavitation issue involving the RHR system while in Mode 4. Westinghouse NSAL 09-08, issued in January 2009, was evaluated by PSEG during recent emergency operating procedure upgrades and the adequacy of the procedure temperature limitations were questioned and evaluated by PSEG engineering. The inspectors found that the engineering evaluations determined that in Mode 4, the temperature of the fluid in the RHR pump suction header could exceed the temperature during a postulated shutdown LOCA, and which could have resulted in cavitation of the RHR system for both injection phase and recirculation. The inspectors reviewed PSEGs system noting that the RHR suction header for each train is cross-connected to share a common flow path from the reactor coolant system (RCS) or RWST. Because of this, PSEG determined that this could affect both RHR trains, making this a safety system functional failure, and that both Salem Unit 1 and Unit 2 have operated in this condition for short time periods in the past. PSEGs review of plant operating history found brief instances in which RHR was operated in shutdown cooling at elevated coolant temperatures where cavitation could be expected if RHR pressure was reduced when actuated for ECCS operation. Therefore, this is considered operation in a condition prohibited by technical specifications and common cause inoperability of independent trains.

The inspectors determined that PSEG conducted an appropriate review of the issue, including an adequate extent of condition and historical review and has implemented corrective actions to address the potential inoperability of RHR in Mode 4 due to cavitation. PSEGs corrective actions, under order 70210967 and PSEG Temporary Operations Standing Order (TSO) 2020-020, included actions to permanently revise the affected procedures and interim actions implementing a TSO to ensure RHR water temperatures are maintained below potential limitations of cavitation.

Screening: The inspectors determined the performance deficiency was minor. Salem Units 1 and 2 Technical Specification 3.5.3.b requires, in part, one operable RHR pump, associated heat exchanger, and a flow path from the RWST and containment sump to the RCS cold and hot legs. Contrary to this, there were brief instances when each unit's RHR was operated in shutdown cooling at RCS temperatures where cavitation is expected if RHR pressure is reduced for ECCS operation. These conditions resulted in common cause inoperability of independent RHR trains. Inspectors determined this issue was minor because it did not adversely affect the Mitigating Systems cornerstone objective, procedure quality attribute, to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage).

Enforcement:

PSEG took actions to restore compliance. This failure to comply with Units 1 and 2 Technical Specification 3.5.3.b constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.

EXIT MEETINGS AND DEBRIEFS

The inspectors verified no proprietary information was retained or documented in this report.

• On August 6, 2020, the inspectors presented the RP Radiological Hazard and Instrumentation Inspection Debrief inspection results to Charles McFeaters, Vice President, and other members of the licensee staff.

• On October 1, 2020, the inspectors presented the integrated inspection results to Mr. Dave Sharbaugh, Plant Manager and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

71111.13 Corrective Action 20857586

Documents

Resulting from

Inspection

71124.05 Engineering Op Eval # 20-007 Evaluation of containment high range radiation detectors for Revision 1

Evaluations operability following Part 21 report from manufacturer

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