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| number = ML16266A224
| number = ML16266A224
| issue date = 09/22/2016
| issue date = 09/22/2016
| title = Salem Nuclear Generating Station, Units 1 and 2 - Integrated Inspection Report 05000272/2016002 and 05000311/2016002
| title = Integrated Inspection Report 05000272/2016002 and 05000311/2016002
| author name = Bower F L
| author name = Bower F
| author affiliation = NRC/RGN-I/DRP/PB3
| author affiliation = NRC/RGN-I/DRP/PB3
| addressee name = Sena P
| addressee name = Sena P
Line 14: Line 14:
| page count = 66
| page count = 66
}}
}}
See also: [[followed by::IR 05000272/2016002]]
See also: [[see also::IR 05000272/2016002]]


=Text=
=Text=
{{#Wiki_filter:T. Joyce UNITED STATES     NUCLEAR REGULATORY COMMISSION REGION I 2100 RENAISSANCE BLVD., SUITE 100 KING OF PRUSSIA, PA 19406-2713                                                               September 22, 2016 Mr. Peter Sena, III  
{{#Wiki_filter:T. Joyce
President and Chief Nuclear Officer  
                                              UNITED STATES
PSEG Nuclear LLC - N09  
                                NUCLEAR REGULATORY COMMISSION
P.O. Box 236 Hancocks Bridge, NJ 08038
                                                  REGION I
SUBJECT: SALEM NUCLEAR GENERATING STATION, UNITS 1 AND 2 - INTEGRATED INSPECTION REPORT 05000272/2016002 AND  
                                    2100 RENAISSANCE BLVD., SUITE 100
05000311/2016002 Dear Mr. Sena:  
                                      KING OF PRUSSIA, PA 19406-2713
                                                September 22, 2016
On June 30, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Salem Nuclear Generating Station, Units 1 and 2 (Salem). The enclosed inspection report documents the inspection results, which were discussed with Mr. Robert DeNight on July 28, 2016, and with Mr. Eric Carr on August 11, 2016, as well as other members of your staff.
      Mr. Peter Sena, III
NRC Inspectors examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.
      President and Chief Nuclear Officer
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
      PSEG Nuclear LLC - N09
The inspectors documented two findings of very low safety significance (Green) in this report. Further, inspectors documented a licensee-identified violation which was determined to be of very low safety significance in this report. The NRC is treating these issues as one finding (FIN)  
      P.O. Box 236
and as two non-cited violations (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.   If you contest the NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission,  
      Hancocks Bridge, NJ 08038
ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional  
      SUBJECT:       SALEM NUCLEAR GENERATING STATION, UNITS 1 AND 2 -
Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Salem. In addition, if you disagree with the cross-cutting aspect assigned to any finding, or a finding not  
                      INTEGRATED INSPECTION REPORT 05000272/2016002 AND
associated with a regulatory requirement in this report, you should provide a response within  
                      05000311/2016002
30 days of the date of this inspection report, with the basis for your disagreement, to the  
      Dear Mr. Sena:
Regional Administrator, Region I, and the NRC Resident Inspector at Salem.  
      On June 30, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
   
      the Salem Nuclear Generating Station, Units 1 and 2 (Salem). The enclosed inspection report
P. Sena - 2 -  In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC's Public Document Room or from  the Publicly Available Records component of the NRC's Agencywide Documents Access and Management System (ADAMS).  ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).  Sincerely,        /RA/  Fred L. Bower, III, Chief Reactor Projects Branch 3 Division of Reactor Projects 
      documents the inspection results, which were discussed with Mr. Robert DeNight on July 28,
Docket Nos.  50-272 and 50-311 License Nos. DPR-70 and DPR-75 
      2016, and with Mr. Eric Carr on August 11, 2016, as well as other members of your staff.
Enclosure: 
      NRC Inspectors examined activities conducted under your license as they relate to safety and
Inspection Report 05000272/2016002 and 
      compliance with the Commissions rules and regulations and with the conditions of your license.
  05000311/2016002    w/Attachment:  Supplementary Information  cc w/encl:  Distribution via ListServ
      The inspectors reviewed selected procedures and records, observed activities, and interviewed
 
      personnel.
P. Sena - 2 -  In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC's Public Document Room or from  the Publicly Available Records component of the NRC's Agencywide Documents Access and Management System (ADAMS).  ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).  Sincerely,        /RA/  Fred L. Bower, III, Chief Reactor Projects Branch 3 Division of Reactor Projects 
      The inspectors documented two findings of very low safety significance (Green) in this report.
Docket Nos.  50-272 and 50-311 License Nos. DPR-70 and DPR-75 
      Further, inspectors documented a licensee-identified violation which was determined to be of
Enclosure: 
      very low safety significance in this report. The NRC is treating these issues as one finding (FIN)
Inspection Report 05000272/2016002 and 
      and as two non-cited violations (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.
  05000311/2016002    w/Attachment:  Supplementary Information  cc w/encl:  Distribution via ListServ
      If you contest the NCV in this report, you should provide a response within 30 days of the date
      of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission,
      ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional
DISTRIBUTION: (via email)  DDorman, RA
      Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory
DLew, DRA 
      Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Salem. In
MScott, DRP  DPelton, DRP  RLorson, DRS  PKrohn, DRS FBower, DRP  RBarkley, DRP
      addition, if you disagree with the cross-cutting aspect assigned to any finding, or a finding not
MGray, DRS
      associated with a regulatory requirement in this report, you should provide a response within
JKulp, DRS MDraxton, DRP  RVadella, DRP 
      30 days of the date of this inspection report, with the basis for your disagreement, to the
PFinney, DRP, SRI 
      Regional Administrator, Region I, and the NRC Resident Inspector at Salem.
AZiedonis, DRP, RI COtt, DRP, AA 
JBowen, RI, OEDO  RidsNrrPMSalem Resource  RidsNrrDorlLpl1-2 Resource 
ROPreports Resource      DOC NAME: G:\DRP\BRANCH3\Inspection Reports\Salem\16Q2\SAL IR 2016002_09-22-2016_Final.docx  ADAMS Accession No.  ML16266A224    SUNSI Review  Non-Sensitive  Sensitive  Publicly Available  Non-Publicly Available  OFFICE RI/DRP RI/DRP RI/DRS RI/DRP RI/DRP NAME  PFinney/RB RBarkley MGray MScott FBower DATE 9/16/16 9/14/16 9/16/16 9/22/16 9/22/16 OFFICIAL RECORD COPY 
1  Enclosure U.S. NUCLEAR REGULATORY COMMISSION  REGION I 
Docket Nos.  50-272 and 50-311 
License Nos.  DPR-70 and DPR-75
Report Nos.  05000272/2016002 and 05000311/2016002 
Licensee:  PSEG Nuclear LLC (PSEG)
  Facility:  Salem Nuclear Generating Station, Units 1 and 2
Location:  P.O. Box 236
  Hancocks Bridge, NJ 08038 
Dates:  April 1, 2016 through June 30, 2016
Inspectors:  P. Finney, Senior Resident Inspector A. Ziedonis, Resident Inspector
E. Burket, Emergency Preparedness Specialist
G. DiPaolo, Senior Reactor Inspector
M. Draxton, Project Engineer
J. Kulp, Senior Reactor Inspector M. Modes, Senior Reactor Inspector R. Nimitz, Senior Health Physicist
T. O'Hara, Reactor Engineer
D. Orr, Senior Reactor Inspector
R. Vadella, Project Engineer  J. Poehler, Senior Materials Engineer 
Approved By:  Fred L. Bower, III, Chief
  Reactor Projects Branch 3
  Division of Reactor Projects 
 
2  TABLE OF CONTENTS  REPORT DETAILS ....................................................................................................................... 51.REACTOR SAFETY .............................................................................................................. 51R01Adverse Weather Protection  ...................................................................................... 51R04Equipment Alignment .................................................................................................. 71R05Fire Protection ............................................................................................................. 71R07 Heat Sink Performance  .............................................................................................. 7 1R08 In-service Inspection Activities  ................................................................................... 7
1R11Licensed Operator Requalification Program  ............................................................ 121R12Maintenance Effectiveness  ...................................................................................... 121R13Maintenance Risk Assessments and Emergent Work Control  ................................ 131R15Operability Determinations and Functionality Assessments  .................................... 14 1R18 Plant Modifications  ................................................................................................... 19 1R19Post-Maintenance Testing  ....................................................................................... 201R20Refueling and Other Outage Activities ...................................................................... 201R22Surveillance Testing  ................................................................................................. 211EP6Drill Evaluation  ........................................................................................................ 222. RADIATION SAFETY .......................................................................................................... 222RS1 Radiological Hazard Assessment and Exposure Controls  ....................................... 22 2RS2Occupational ALARA Planning and Controls  ........................................................... 242RS3 In-Plant Airborne Radioactivity Control and Mitigation  ............................................. 25
2RS4 Occupational Dose Assessment  .............................................................................. 26 2RS5Radiation Monitoring Instrumentation  ...................................................................... 272RS7Radiological Environmental Monitoring Program (REMP)  ....................................... 284.OTHER ACTIVITIES ............................................................................................................ 294OA1Performance Indicator Verification ............................................................................ 294OA2Problem Identification and Resolution  ..................................................................... 294OA3Follow-Up of Events and Notices of Enforcement Discretion.................................... 394OA5 Other Activities .......................................................................................................... 43 4OA6Management Meetings ............................................................................................. 454OA7Licensee-identified Violations ................................................................................... 45 ATTACHMENT: SUPPLEMENTARY INFORMATION ............................................................... 46SUPPLEMENTARY INFORMATION ........................................................................................ A-1KEY POINTS OF CONTACT .................................................................................................... A-1LIST OF ITEMS OPENED, CLOSED AND DISCUSSED ......................................................... A-2LIST OF DOCUMENTS REVIEWED ........................................................................................ A-3LIST OF ACRONYMS ............................................................................................................. A-16
3  SUMMARY  Inspection Report (IR) 05000272/2016002, 05000311/2016002; 04/01/2016 - 06/30/2016;
Salem Nuclear Generating Station Units 1 and 2; Operability Determinations and Functionality
Assessments; Follow-Up of Events and Notices of Enforcement Discretion.
This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors.  The inspectors documented one self-revealing finding of very low safety significance (Green), one non-cited violation (NCV), one finding (FIN)
and one licensee identified violation.  The significance of most findings is indicated by their color
(i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection
Manual Chapter (IMC) 0609, "Significance Determination Process (SDP)," dated April 29, 2015.  Cross-cutting aspects are determined using IMC 0310, "Aspects Within Cross-Cutting Areas," dated December 4, 2014.  All violations of NRC requirements are dispositioned in accordance with the NRC's Enforcement Policy, dated February 4, 2015.  The NRC's program for
overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, "Reactor Oversight Process," Revision 5, dated February 2014.
Cornerstone:  Mitigating Systems and Initiating Events
  Green.  The inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," because, from June 15, 2016 until July 26, 2016, PSEG did not accomplish actions necessary to provide adequate confidence that a structure, system, and component (SSC) would perform satisfactorily in service (an activity affecting quality) as prescribed by a documented procedure.  Specifically, although PSEG had concluded Salem Unit 2 is susceptible to baffle bolt failure due to its design and operating life (but less susceptible than
Salem Unit 1), PSEG inadequately implemented Procedure OP-AA-108-115, "Operability
Determinations & Functionality Assessments," Sections 4.7.14 followed by Sections
4.7.18-4.7.20 to perform an operability evaluation (OpEval) to justify continued operation of the unit until the next refueling outage.  PSEG's immediate corrective actions included entering the issue into its corrective action program (NOTF 20736630) and documenting an
operability evaluation to support the basis for functionality of the baffle structure and the
operability of the emergency core cooling system (ECCS) and reactivity control systems.    This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences, in that degradation of a significant number of baffle bolts
could result in baffle plates dislodging following an accident.  This issue was dispositioned as
more than minor because it was also similar to example 3.j of IMC 0612, Appendix E, "Examples of Minor Issues," in that the condition resulted in reasonable doubt of operability of the ECCS and additional analysis was necessary to verify operability.  In accordance with
IMC 0609.04, "Initial Characterization of Findings," and Exhibit 2 of IMC 0609, Appendix A,
"The Significance Determination Process for Findings At-Power," issued June 19, 2012, the
inspectors screened the finding for safety significance and determined it to be of very low safety significance (Green), since the finding did not represent an actual loss of system or function.  After inspector questioning, PSEG performed OpEval 2016-015, which provided
sufficient bases to conclude the Unit 2 baffle assembly would support ECCS and control rod
system operability until the next refueling outage.  This finding is related to the cross-cutting 
4  aspect of Operating Experience because PSEG did not effectively evaluate relevant internal and external operating experience.  Specifically, PSEG did not adequately evaluate the impact of degraded baffle bolts in Unit 2 when directly relevant operating experience was identified at Unit 1. [P.5] (Section 1R15)    Green.  A Green, self-revealing finding (FIN) was identified against MA-AA-716-010, "Maintenance Planning Process," Revision 18, when PSEG work orders (WOs) did not specify the appropriate procedure to perform satisfactory modification testing of the main
generator automatic voltage regulator (AVR) protective relay (model STV1).  Consequently,
the relay actuated below its design setpoint on February 4, 2016, resulting in an automatic
trip of the Unit 2 main turbine and reactor.  PSEG entered the issue in their Corrective Action Program (CAP) and performed a root cause evaluation (RCE), replaced the failed STV1 relay with a properly tested relay, verified other STV relays were appropriately tested
as an extent of condition, and initiated an action to revise Laboratory Testing Services (LTS)
department relay test procedures to ensure all applicable acceptance criteria will be
incorporated.  The inspectors determined that a performance deficiency existed because PSEG WOs did
not specify the appropriate procedure to perform satisfactory modification testing of the main
generator AVR protection relay.  This issue was more than minor since it was associated
with the procedure quality attribute of the Initiating Events cornerstone and adversely
impacted its objective to limit the likelihood of events that upset plant stability (turbine and reactor trip) and challenge critical safety functions.  Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety
significance, or Green, since mitigating equipment relied up to transition the plant to stable
shutdown remained available.  The finding had a cross-cutting aspect in the area of Human
Performance, Work Management, in that the PSEG did not adequately implement the work process to coordinate with engineering and maintenance departments as needed to appropriately plan the STV1 relay modification test WO. [H.5] (Section 4OA3.3)
Other Findings  A violation of very low safety significance that was identified by PSEG was reviewed by the inspectors.  Corrective actions taken or planned by PSEG have been entered into PSEG's CAP.  This violation and corrective actions tracking number are listed in Section 4OA7 of this report. 
5  REPORT DETAILS  Summary of Plant Status 
Unit 1 began the inspection period at 100 percent power.  The unit was shut down for a
refueling outage on April 14. 
Unit 2 began the inspection period at 100 percent power.  The unit remained at or near 100 percent power until June 28, when the unit tripped due to actuation of the main generator
protection system.  The unit remained shut down at the end of the inspection period.
1. REACTOR SAFETY  Cornerstones:  Initiating Events, Mitigating Systems, and Barrier Integrity  1R01 Adverse Weather Protection (71111.01 - 1 sample)  .1 Summer Readiness of Offsite and Alternate Alternating Current Power Systems  a. Inspection Scope  The inspectors reviewed plant features and procedures for the operation and continued availability of the offsite and alternate alternating current (AC) power system to evaluate readiness of the systems prior to seasonal high grid loading on May 31.  The inspectors
reviewed PSEG's procedures affecting these areas and the communications protocols
between the transmission system operator and PSEG.  This review focused on changes to the established program and material condition of the offsite and alternate AC power equipment.  The inspectors assessed whether PSEG established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability
of both the offsite AC power system and the onsite alternate AC power system.  The
inspectors evaluated the material condition of the associated equipment by interviewing the responsible system manager, reviewing condition reports and open WOs, and walking down portions of the offsite and AC power systems including the 500 kilovolt (kV). 
b. Findings  No findings were identified.  1R04 Equipment Alignment  .1 Partial System Walkdown (71111.04Q - 4 samples)  a. Inspection Scope  The inspectors performed partial walkdowns of the following systems:  Unit 1, 1A and 1C 125V direct current (DC) system during 1B 125V DC battery inoperability on April 6  Unit 1, Containment penetrations during irradiated fuel moves on April 19   
6    Unit 2, Service water (SW) system during 21 SW pump emergent repairs on June 7  Unit 2, Auxiliary building ventilation with damper 2ABV2 failed open on June 16  The inspectors selected these systems based on their risk-significance relative to the
reactor safety cornerstones at the time they were inspected.  The inspectors reviewed applicable operating procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), technical specification(s) (TSs), WOs, notifications (NOTFs), and the
impact of ongoing work activities on redundant trains of equipment in order to identify
conditions that could have impacted the system's performance of its intended safety functions.  The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable.  The inspectors examined the material condition of the components and
observed operating parameters of equipment to verify that there were no deficiencies. 
The inspectors also reviewed whether PSEG staff had properly identified equipment
issues and entered them into the CAP for resolution with the appropriate significance
characterization.  b. Findings  No findings were identified.  .2 Full System Walkdown (71111.04S - 1 sample)  a. Inspection Scope  On June 22, 2016, the inspectors performed a complete system walkdown of accessible
portions of the Unit 2 safety injection (SI) to verify the existing equipment lineup was correct.  The inspectors reviewed operating procedures, surveillance tests, drawings, equipment line-up check-off lists, and the UFSAR to verify the system was aligned to
perform its required safety functions.  The inspectors also reviewed electrical power availability, component lubrication and equipment cooling, hanger and support
functionality, and operability of support systems.  The inspectors performed field walkdowns of accessible portions of the systems to verify as-built system configuration matched plant documentation, and that system components and support equipment
remained operable.  The inspectors confirmed that systems and components were
aligned correctly, free from interference from temporary services or isolation boundaries, environmentally qualified, and protected from external threats.  The inspectors also examined the material condition of the components for degradation and observed operating parameters of equipment to verify that there were no deficiencies.  Additionally, the inspectors reviewed a sample of related notifications and WOs to
ensure PSEG appropriately evaluated and resolved any deficiencies.
  b. Findings  No findings were identified.   
7  1R05 Fire Protection  .1 Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)  a. Inspection Scope  The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features.  The inspectors verified that PSEG controlled combustible materials and ignition sources in accordance with
administrative procedures.  The inspectors verified that fire protection and suppression
equipment was available for use as specified in the area pre-fire plan, and passive fire
barriers were maintained in good material condition.  The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.    Unit 2, Spent fuel (SF) and component cooling heat exchangers (HXs) on May 12  Unit 2, Boric acid evaporator unit and chemistry area on May 20  Unit 2, SW pump bays during 21 SW pump maintenance on June 8  Unit 2, 2B and 2C emergency diesel generator (EDG) rooms on June 16  Unit 2, Chiller room while protected on June 16  b. Findings  No findings were identified.
1R07 Heat Sink Performance (711111.07A - 1 sample)  a. Inspection Scope  The inspectors reviewed the 12 SI pump lube oil cooler readiness and availability to
perform its safety functions.  The inspectors reviewed the design basis for the
component and verified PSEGs commitments to NRC Generic Letter 89-13, "Service Water Requirements Affecting Safety-Related Equipment."  The inspectors performed inspection of the as-found conditions, and discussed the results of previous inspections
with PSEG staff.  The inspectors verified that PSEG initiated appropriate corrective
actions for identified deficiencies.  The inspectors also verified that the number of tubes
plugged within the HX did not exceed the maximum amount allowed.
b. Findings  No findings were identified.
1R08 In-service Inspection Activities (71111.08 1 sample)    a. Inspection Scope  Inspectors from the NRC Region I Office, specializing in materials and in-service examination activities, observed portions of PSEG's activities involving baffle bolt examinations and replacements during the Salem Unit 1 spring 2016 refueling outage
(1R24).  PSEG notified the NRC of problems with baffle bolts in Event 
8  Notification 51902, "Anomalies Identified during Visual Inspection of Reactor Vessel Internals."  During May 17-19, 2016, and June 20-23, 2016, inspectors conducted an inspection of PSEG's evaluation of the baffle bolt ultrasonic testing results and visual examination performed during 1R24.  The inspectors reviewed documentation,
interviewed personnel, and reviewed video recordings of visual examinations performed
during the current and previous refueling outages.  The inspectors also observed in-
progress baffle bolt replacement activities.  Nondestructive Examination and Welding Activities (Section 02.01)  The inspectors conducted a review of PSEG's implementation of in-service inspection (ISI) program activities for monitoring degradation of the reactor coolant system boundary, risk significant piping and components, and containment systems during Salem Unit 1 refueling outage 1R24.  The sample selection was based on the inspection
procedure objectives and risk priority of those pressure retaining components in these
systems where degradation would result in a significant increase in risk.  The inspectors
observed in-process nondestructive examination (NDE), reviewed records, and interviewed personnel to verify the following:  a) that non-destructive activities were performed in accordance with American Society of Mechanical Engineers (ASME) Boiler
and Pressure Vessel Code Section XI, 2004 Edition, no Addenda, requirements; b) that indications and defects, if present, were dispositioned in accordance with the ASME
Code or an NRC approved alternative; and, c) that relevant indications were compared to previous examinations to determine if any changes occurred.  The inspectors reviewed the ultrasonic testing (UT) procedure used for the examination
of the Unit 1 baffle bolts to verify it met the requirements of the ASME Boiler and
Pressure Vessel Code and the applicable guidance in the Electric Power Research
Institute's Materials Reliability Program (MRP-227 and 228).  The inspectors reviewed the UT data records for the examinations performed during the 1R24 refueling outage to verify that activities were performed in accordance with applicable examination
procedures.
The inspectors reviewed video from the visual examination of the baffle bolts performed
in the current refueling outage (RFO).  The inspectors also reviewed video of visual examinations performed during Unit 1 RFOs in 2001, 2013, and 2014 to assess the as-found conditions of the baffle bolts.  The inspectors reviewed certifications of the NDE
technicians performing the examinations to verify the examinations were performed by qualified individuals in accordance with approved procedures and the results reviewed and evaluated by certified Level III NDE personnel.    The inspectors performed a sample of observations of NDE activities and reviewed
records of NDE activities.  The review sample consisted of two or three types of NDE
activities, including at least one volumetric examination.
ASME Code Required Examinations  Salem Unit 1, Liquid Penetrant Report No. PT-16-002, 11-RHRHEX Vessel Support, 4/15/16, (Summary No.205170) [record review] Salem Unit 1, Liquid Penetrant Report No. PT-16-001, Pipe Lugs 8-RH-2116-10PL-1
through 4, 4/15/16, (Summary No. 263631) [record review]   
9  Salem Unit 1, Liquid Penetrant Report No. PT-16-004, Pipe to Penetration IA, Component 12 SJ-2152-36PS-4, 4/19/16, (Summary No. 263904) [record review] Salem Unit 1, Liquid Penetrant Report No. PT-16-003, Inlet Nozzle To 11  Charging Pump, Component 6-CV-2111-14R1, 4/15/16, 
(Summary No. 220757) [record review] Salem Unit 1, Liquid Penetrant Report No. PT-16-005, Pipe-to-Valve (11CS48) [record review] Component ID: 8-CS-2114-60, 4/15/16, (Summary No. 56640) Salem Unit 1, Ultrasonic examination (Summary #006325) Report UT-16-039, Component ID: 1-PZR-20, Pressurizer, shell J weld [Observed] Component ID: 16-BFN-2111-IRS, Inside Radius Section Ultrasonic  Examination, 16-BF-2111, Report UT-16-013, Steam Generator #11,
(Summary #204201) [Observed] Component 4-PRN-1100-IRS, Pressurizer Relief Nozzle, inside Radius Section, Ultrasonic Examination, (Summary #007000), UT-16-031, [Observed] 
Observation of Baffle Bolt Replacement Activities  The inspectors observed electrical discharge machining activities on a baffle bolt location.  The inspectors observed the bolt hole milling activities for a baffle bolt.  The
inspectors verified that bolt replacement activities were being performed in accordance
with approved procedures. 
Other Augmented, License Renewal or Industry Initiative Examinations 
PSEG did not schedule augmented inspections in the outage scope for 1R24.
Review of Relevant Indication(s) Evaluated and Accepted for Continued Service  PSEG did not have any originally rejectable indications since the end of their prior outage, which were later accepted for continued use after evaluation.  Modifications, Repairs, or Replacements Consisting of Welding on Pressure Boundary Risk Significant Systems  The inspectors reviewed Design Change Package 80092579, Salem Unit 1 - Steam Generator (SG) Bowl Drain Repair, for SGs 11, 12, 13, and 14.  This change removed
Alloy 600 and associated 82/182 weld material from each SG channel head bowl drain
plug to reduce the potential for primary water stress corrosion cracking.  The inspectors
determined overall whether the modifications were completed in accordance with ASME Section XI as a repair/replacement activity.  Specifically, the inspectors reviewed the machining and welding procedures used to complete the modifications, reviewed the
training of the machinists, welders and laborers qualified on a mockup of the channel
heads, and reviewed the mockup training completed by all craft personnel on the project. 
The inspectors reviewed the in-process NDE and the final NDE procedures to determine
whether the change was implemented in accordance with ASME Section XI repair/replacement requirements.   
10  PWR Vessel Upper Head Penetration Inspection Activities (Section 02.02)  The Salem Unit 1 reactor pressure vessel head was replaced with an Alloy 690 head in
2005.  The inspectors determined that reactor pressure vessel head examinations (per
ASME Code Case N-729) were not required during 1R24.
Boric Acid Corrosion Control Inspection Activities (Section 02.03) 
The inspectors reviewed the Boric Acid Corrosion Control program and implementing
PSEG procedures, and discussed the outage inspections with program engineers.  The
inspectors also reviewed documentation, corrective action process notifications,
including photographic records, of the conditions identified during the plant shutdown.  The inspectors also reviewed a sample of notifications recommending repairs to identified conditions and a sample of boric acid engineering evaluations performed to
determine the priority of repair of identified boric acid corrosion on safety significant
piping and components.  Boric acid inspections were conducted on safety significant
piping and components inside the containment structure during walk downs conducted by PSEG staff with the plant at normal pressure and temperature conditions.  The inspectors reviewed a sample of photos and visual inspection records to verify that boric
acid leakage was being appropriately identified and non-conforming conditions of boric
acid leaks were documented in the CAP with a focus on areas that could cause
degradation of safety significant components.  The inspectors verified that potentially more significant boric acid deficiencies were being adequately dispositioned by reviewing a sample of evaluations documented in the
following PSEG condition reports:  20682192, 20699859, 20699820, 20699910,
20704139, 20707125, 20712774, 20713572, 20722494, 20682192, 20699859,
20707125, 20722494, 70179375, 20699820, 20704139, 70185980, 20712774, 20713573, 20713572. 
These reviews verified whether the corrective actions were consistent with the
requirements of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI.  The
inspectors reviewed the engineering evaluations associated with these condition reports
to verify whether equipment or components wetted or impinged upon by boric acid solutions were properly analyzed for degradation that might impact their function. 
Steam Generator Tube Inspection Activities (Section 02.04) 
PSEG's Base Eddy Current Test (ECT) program consisted of:  (a) 100 percent bobbin probe inspection of straight and U-bend tubes, (b) 50 percent Hot Leg coverage of Top of Tubesheet area with an array probe, (c) 3 tube periphery tube array testing, and
various + Point sampling strategies (for U-bend and Dent/Ding inspections) of in-service
tubes were completed in each SG.  The inspectors reviewed the 1R24 SG tube
Degradation Assessment, ECT examination scope and expansion criteria to verify that it met TS requirements, Electric Power Research Institute (EPRI) guidelines, and commitments made to the NRC.  The inspectors also verified that the ECT scope included areas of degradation that were known to represent potential ECT challenges
such as the top of tube sheet, tube support plates, and U-bends.  Upon completion of
eddy current (EC) examinations and the evaluation of all data, PSEG staff determined
that six tubes required plugging.  The affected tubes were plugged during 1R24.  The 
11  inspectors verified that the affected tubes were properly screened against the in situ screening criteria and that none of the tube indications required in-situ pressure testing.  The inspectors observed portions of the ECT being performed and verified whether: (1) the appropriate probes were used for identifying the expected types of degradation,
(2) calibration requirements were adhered to, and (3) probe travel speed was in
accordance with procedural requirements.  The inspectors performed a review of the site-specific qualifications for the techniques being used, and verified whether the ECT data analyses were adequately performed per EPRI and PSEG specific guidelines.  The
inspectors selected a sample of degraded tubes and compared them to the previous
outage operational assessment to assess PSEGs prediction capabilities.  The inspectors
also reviewed a sample of EC data, and verified, through discussion with the data analyst that the analytical techniques used to evaluate the inspection data were adequate.  The inspectors further verified that the assumed NDE flaw sizing accuracy
was consistent with data from EPRI examination technique specification sheet or
applicable performance demonstration.  Finally, the inspectors reviewed the
qualifications for the EC data collection personnel, a sample of the inspection supervision personnel qualifications and a sample of the qualifications of staff responsible for interpretation and resolution analysis to determine whether the records were complete. The inspectors observed a portion of a plug integrity visual examination per procedure 81DP-9RC40, "Steam Generator Channel Head Video Inspection," to verify that those
tubes that had been previously plugged did not exhibit any leakage.  No evidence of plug
leakage was identified.  Additionally, the inspectors observed a portion of the secondary
sludge lancing and foreign object search and retrieval (FOSAR) inspections.  No
significant foreign materials or quantity of sludge were identified. During the prior operating cycle previous to the current refueling outage 1R24, the inspectors determined whether leakage from each SG was measured, via sampling of each SG, for the complete prior operating cycle (leakage was not measured). PSEG staff completed secondary side inspections and sludge lancing of all SG's.  The inspectors reviewed the results to determine that no loose parts affecting tube integrity
were noted and that other SG related inspections were performed without repairs. 
PSEG staff performed a plug integrity visual examination to verify that those tubes that
had been previously plugged did not exhibit leakage.  From this visual exam, PSEG staff documented excessive boron buildup around tube plug 43-34 in the SG 11 cold leg and initiated CR-2016-29172 to track the evaluation of the condition.  PSEG staff also
initiated Notification 20726743 to track the condition.  PSEG Engineering staff review of the plug concluded that no evidence of plug leakage had occurred.  Additionally,
secondary sludge lancing and FOSAR inspections were performed in each SG.  No foreign materials, which could damage SG tubes, were identified.  The inspectors reviewed the PSEG evaluations and information to determine the conclusions were technically supported.  Identification and Resolution of Problems (Section 02.05) 
The inspectors reviewed a sample of condition reports, which identified NDE indications, deficiencies and other nonconforming conditions since the previous, 1R23, refueling
outage.  The inspectors verified that nonconforming conditions were properly identified, 
12  characterized, evaluated, corrective actions identified and dispositioned, and appropriately entered into the CAP.  b.      Findings  Introduction.  The inspectors determined the level of degradation of Unit 1 baffle bolts reported to the NRC as a condition not previously analyzed is an issue of concern that warrants additional inspection to determine whether a performance deficiency exists.  As a result, the NRC opened a unresolved item (URI).
Description.  Additional inspection is warranted to determine whether a performance deficiency exists related to Event Notification 51902, dated May 3, 2016, in which PSEG reported to the NRC that the level of degradation of baffle bolts was a condition not previously analyzed.  The baffle bolts secure plates in the reactor core barrel to form a
shroud around the fuel core to direct reactor coolant flow upward through the fuel
assemblies.  In order to determine if a performance deficiency exists, the inspectors will
review the results of PSEG's RCE which will be completed at a later date.
(URI 05000272/2016002-01, Baffle-Former Bolts with Identified Anomalies)  1R11 Licensed Operator Requalification Program (71111.11Q - 1 sample) 
Quarterly Review of Licensed Operator Requalification Testing and Training  a. Inspection Scope  The inspectors observed licensed operator simulator training on June 8, 2016, which
included a heater drain pump oil leak, a steam generator feed pump trip, and a steam
generator tube rupture.  The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures.  The inspectors assessed the
clarity and effectiveness of communications, implementation of actions in response to
alarms and degrading plant conditions, and the oversight and direction provided by the
control room supervisor.  The inspectors verified the accuracy and timeliness of the
emergency classification made by the shift manager and the TS action statements entered by the shift technical advisor.  Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems. 
  b. Findings  No findings were identified. 
1R12 Maintenance Effectiveness (71111.12Q - 3 samples)  a. Inspection Scope  The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on SSC performance and reliability.  The inspectors reviewed system health reports, CAP documents, maintenance WOs, and maintenance rule (MR)
basis documents to ensure that PSEG was identifying and properly evaluating performance problems within the scope of the MR.  For each sample selected, the inspectors verified that the SSC was properly scoped into the MR in accordance with 
13  10 CFR 50.65 and verified that the (a)(2) performance criteria established by PSEG staff was reasonable.  As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). 
Additionally, the inspectors ensured that PSEG staff was identifying and addressing common cause failures that occurred within and across MR system boundaries.  Unit 2, 22SW535, unsatisfactory stroke time of SW accumulator supply valve to 22 containment fan cooler unit (CFCU) on May 2  Unit 2, Circulating water system 125V DC battery degradation on May 23  Common, MR URI, 05000272;311/2015008-01:  Inadequate MR  System Performance Criteria Selection, closeout on May 1  b. Findings  No findings were identified.  Additional inspection results regarding the URI closeout are
documented in Section 4OA5. 
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 5 samples)  a. Inspection Scope 
The inspectors reviewed station evaluation and management of plant risk for the
maintenance and emergent work activities listed below to verify that PSEG performed the appropriate risk assessments prior to removing equipment for work.  The inspectors selected these activities based on potential risk significance relative to the reactor safety
cornerstones.  As applicable for each activity, the inspectors verified that PSEG
personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the
assessments were accurate and complete.  When PSEG performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.  The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the station's probabilistic risk analyst to verify plant conditions were
consistent with the risk assessment.  The inspectors also reviewed the TS requirements
and inspected portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met.  Unit 1, 11SW223, SW outlet valve to 11 CFCU, failure to close on April 7  Unit 1, Reactor core baffle-to-former bolt expanded inspection scope on April 22  Unit 2, Appendix R safe shutdown panel failed indication on May 9  Unit 2, 2A subcooling margin monitor failure on May 26  Unit 2, Yellow risk with one offsite power source unavailable on June 1  b. Findings  No findings were identified.   
14  1R15 Operability Determinations and Functionality Assessments (71111.15 - 9 samples)  a. Inspection Scope 
The inspectors reviewed operability determinations for the following degraded or
non-conforming conditions based on the risk significance of the associated components
and systems:  Unit 1, Corrosion and metal loss identified during inspection of 11 SW header on April 23  Unit 1, Immediate operability determination (IOD) of the degraded condition of the  baffle-former bolts on April 27  Unit 1, 1 Emergency control air compressor shutdown on April 27  Unit 1, SI thermal relief valve failures on May 2  Unit 1, 13 turbine-driven auxiliary feedwater (AFW) pump degraded performance  on May 8  Unit 1, 11 diesel fuel oil storage tank high particulates on May 18  Unit 2, IOD of the degraded condition of the baffle-former bolts identified from Unit 1    operating experience on April 27  Unit 2, 125V DC battery degraded cell post connections on May 2  Common, 10 CFR Part 21 issue related to safety-related 4kV breakers on May 16  The inspectors evaluated the technical adequacy of the operability determinations to
assess whether TS operability was properly justified and the subject component or
system remained available such that no unrecognized increase in risk occurred.  The
inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to PSEG's evaluations to determine whether the components or systems were operable.  The inspectors confirmed, where appropriate, compliance with
bounding limitations associated with the evaluations.  Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by PSEG.  b. Findings 
Introduction.  The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," because, from June 15, 2016
until July 26, 2016, PSEG did not accomplish actions necessary to provide adequate confidence that an SSC would perform satisfactorily in service (an activity affecting quality) as prescribed by a documented procedure.  Specifically, although PSEG had concluded Salem Unit 2 is susceptible to baffle bolt failure due to its design and operating life (but less susceptible than Salem Unit 1), PSEG inadequately implemented
Procedure OP-AA-108-115, "Operability Determinations & Functionality Assessments," by not performing Section 4.7.14 followed by Sections 4.7.18-4.7.20 to perform an operability evaluation (OpEval) to justify continued operation of the unit until the next
refueling outage.  In particular, PSEG incorrectly exited their procedure on June 15,
2016, and re-entered it to complete these steps on July 26, 2016, based on discussions
with the NRC.  The operability evaluation provided appropriate justification for the licensee's plans to examine the baffle-former bolts at the next Unit 2 RFO.   
15  Description.  On April 22, 2016, PSEG identified baffle-former ("baffle") bolt degradation at Salem Unit 1 that was determined to be unanalyzed because it did not meet the minimum acceptable bolt pattern analysis developed to support plant startup.  PSEG staff identified that 192 baffle bolts out of a total population of 832 were considered
degraded.  On May 4, 2016, due to the number of degraded baffle bolts discovered on
Unit 1, PSEG staff determined that it was necessary to perform an extent of condition
review for the baffle bolts on Unit 2.  PSEG entered this issue into the corrective action program as NOTF 20727590 and completed an immediate operability determination (IOD) to evaluate the Unit 2 baffle bolts and baffle assembly structure in accordance with
PSEG procedure OP-AA-108-115, "Operability Determinations & Functionality
Assessments," Section 4.7.4. 
The inspectors reviewed the design basis and current licensing basis documents for Unit 2 to identify the specific safety functions of the baffle bolts.  The inspectors identified
that the baffle bolts are part of the baffle assembly structure located in the reactor
pressure vessel.  The bolts secure a series of vertical metal plates called baffle plates,
which help direct water up through the nuclear fuel assemblies to ensure proper cooling of the fuel.  A sufficient number of baffle bolts are required to secure the plates to ensure proper core flow during normal and postulated accident conditions, and also to ensure
that control rods can be inserted to shut down the reactor. 
On June 21, 2016, the inspectors reviewed the IOD as part of a detailed review of the
ongoing baffle bolt activities at Salem and noted that the IOD concluded that there was reasonable assurance that the Unit 2 reactor assembly was operable, but required additional evaluation due to the conditions observed in Unit 1.  Specifically, the IOD
concluded that there was reasonable assurance that the Unit 2 reactor assembly was
operable pending further evaluation based upon the following factors:  (1) Unit 2 had
fewer effective full power years of operation than Unit 1; (2) a baffle bolt visual examination completed during the most recent Unit 2 2R21 refueling outage (fall 2015) did not identify any visual deficiencies; and, (3) there was no current indication of reactor
fuel pin leakage in Unit 2, which could be caused by baffle bolt failure and subsequent
fretting.  The inspectors' review of PSEG's IOD concluded that the IOD provided
sufficient technical detail to support the initial conclusion that there was reasonable
assurance, based on the limited information available, that the Unit 2 baffle bolts would retain sufficient capability to perform their intended functions.  PSEG procedure OP-AA-108-115, Section 4.7.11 directs that "if there is a reasonable expectation that the SSC is
operable, but a more rigorous evaluation is deemed warranted, then update the current
notification or initiate a notification for Engineering to prepare a Technical Evaluation to
support the prompt determination of operability."  The immediate actions section of NOTF 20727590 requested a work order be generated to perform an extent of condition review for Unit 2 baffle bolts.  The Station Ownership Committee (SOC) screening of
NOTF 20727590 on May 6, 2016, assigned a work order to Engineering "to ensure that
Operations is provided the Technical Evaluation product.  This will allow review for
assessment of operability as required."  From review of the daily running log of baffle
bolt action items spreadsheet, the inspectors noted that on May 4, 2016, action EOC.2 to "perform an operability evaluation for Unit 2" was closed to EOC.7-9, to complete an adverse condition monitoring plan, an operational decision making document, and a
Technical Evaluation in lieu of an OpEval.  Consistent with this decision, on May 26,
2016, the Salem plant manager discussed with the senior resident inspector PSEG's
views that an operability evaluation was not required or being developed.  In response, 
16  the inspectors shared their understanding of PSEG procedure guidance and regulatory requirements in this regard. 
Between May 6 and June 15, 2016, PSEG engineering performed Technical Evaluation 70187161, "Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt
Failure."  The purpose of the Technical Evaluation was to determine the potential for
baffle bolt degradation in Unit 2 based upon the results of visual and ultrasonic examination results observed in Unit 1, and to identify and evaluate key factors that could potentially impact the safe operation of Unit 2 for the remainder of the current
operating cycle.  The Technical Evaluation evaluated the key factors that affect
irradiation assisted stress corrosion cracking (IASCC).  Additionally, the Technical
Evaluation assessed the safety consequences of the degraded baffle bolts in the as-found condition in Unit 1.  The Technical Evaluation conclusion summary indicated that Unit 2 is susceptible to baffle bolt failure due to its design and operating life; that any
degradation in Unit 2 would be less advanced that that observed in Unit 1; and that
PSEG should exercise heightened awareness and monitoring of Unit 2 due to this
vulnerability.  The Technical Evaluation also concluded that Unit 1 could have safely shut down and the core would be cooled by demonstrating that control rod insertability is assured and a core coolable geometry was maintained.  Thus the Technical Evaluation concluded that Unit 2 could also be shut down and cooled based upon the conclusion
reached regarding Unit 1.  Following completion of the Technical Evaluation on June 15,
PSEG did not continue on in the operability determination process. 
  The inspectors assessed PSEG's Technical Evaluation 70187161 during an onsite inspection which took place from June 21-23, 2016.  PSEG concluded in Technical Evaluation 70187161, that Salem Unit 2 is susceptible to baffle bolt failure due to its
design and operating history, but less so than observed in Salem Unit 1.  The inspectors
determined this conclusion met PSEG's definition of a "degraded condition" as defined in procedure OP-AA-115-108, Section 2.4.  Section 2.4 defines a degraded condition as "A condition in which the qualification of an SSC or its functional capability is reduced." 
Section 2.4 lists "reduced reliability" as an example of a degraded condition and "aging"
as an example of a condition that can reduce the capability of a system.  The inspectors
noted that IASCC is a time dependent aging degradation mechanism and baffle bolt
failures reduce the functional capability and reliability of the baffle assembly.  Consequently the Technical Evaluation describes a degraded condition in the Unit 2 baffle assembly.  Since the Technical Evaluation concluded that the reactor could be
shut down and cooled based upon the assessment of safety consequences, the
inspectors concluded that PSEG considered that the reactivity control and emergency core cooling systems were operable.  As a result, the inspectors concluded that PSEG should have continued on in the operability determination process as described in Section 4.7.14, "Operable but Degraded or Nonconforming," and declared both the
reactivity control and emergency core cooling systems "operable but degraded."  Once a
SSC is determined to be "operable but degraded," Section 4.7.18 directs that "An
OpEval will be requested based on a declaration of operable but degraded or
nonconforming."  Section 4.7.19 directs Engineering to "Prepare and review and OpEval."  Section 4.7.20 directs Operations to approve or disapprove the OpEval when Engineering completes it.  Sections 4.7.14, 4.7.18, 4.7.19 and 4.7.20 were not
implemented by PSEG.
The inspectors acknowledged that licensees apply judgment in these decisions and can use a graded approach regarding the level of detail.  In this particular instance, the 
17  inspectors considered that operating experience was available that showed the Unit 2 baffle bolts were subject to IASCC and that plants of similar design (4-loop Westinghouse pressurized water reactors with a down-flow configuration and baffle bolts
of 347 stainless steel material and similar dimensions) were subject to greater amounts
of bolt degradation compared to other reactor designs.  Furthermore, the inspectors
noted the baffle bolts had experienced levels of neutron radiation exposure above the
threshold for IASCC initiation as referenced in NUREG/CR-7027, "Degradation of LWR Core Internal Materials due to Neutron Irradiation." 
The inspectors conducted an exit meeting on June 23, 2016, describing a potential
violation of 10 CFR Part 50 Appendix B, Criterion 5, "Instructions, Procedures, and
Drawings," for PSEG not completing the OpEval and assessing the effect of the operability of the ECCS and rod control system based upon the functionality of the baffle former assembly.  Consistent with the change made by PSEG staff to the Salem action
item list on May 4, 2016, to not perform an OpEval, the PSEG Compliance Director
indicated that an operability evaluation was not required and therefore they disagreed
with this finding.  The inspectors determined that Engineering did not perform an OpEval as directed by
OP-AA-108-115 Section 4.7.19, which states "PREPARE and REVIEW an OpEval.  The
OpEval Form (Attachment 1), or a facsimile, may be used to document the engineering
evaluation (Engineering)."  Because an OpEval was not prepared, Operations did not
have the opportunity to approve or disapprove an OpEval as required by OP-AA-108.115, Section 4.7.20 which states:  "When Engineering completes the OpEval, then APPROVE or DISAPPROVE." 
In summary, Technical Evaluation 70187161 concluded Unit 2 is susceptible to IASCC
baffle bolt degradation and that the expected degradation should be less than that observed in Unit 1.  The inspectors assessed that PSEG's conclusions concerning the susceptibility and expected degradation in Unit 2 was adequately supported.  However,
the inspectors concluded that the Technical Evaluation did not provide adequate
confidence that SSCs (baffle bolts supporting ECCS) would perform satisfactorily in service to justify continued operation of Unit 2 until the next refueling outage in the
spring of 2017 in that line break size assumptions were not adequately supported.  Following discussions with NRC Region I management and the inspectors, PSEG staff subsequently completed an operability evaluation (OpEval 2016-015) on July 26, 2016. The OpEval compared the differences in the operating history and parameters between
Unit 1 and Unit 2 and again concluded that Unit 2 was less susceptible than Unit 1 primarily due to significantly fewer thermal cycles and fewer effective full power years (EFPY) of operation.  The OpEval concluded that operability was supported although
"the Unit 2 baffle assemblies are considered degraded since Unit 2 is susceptible to
degraded baffle bolts."  Based upon a qualitative analysis, PSEG's OpEval stated that
Unit 2 can accommodate 38 percent degraded baffled-former bolts (distributed across 
the assembly) and remain within the acceptable bolting pattern analysis patterns assuming the dynamic loads of a large break loss of coolant accident.  The inspectors concluded that PSEG's OpEval 2016-015 provided an adequate basis to conclude that the Unit 2 baffle assembly would support ECCS and rod control system continued
operation until the planned refueling outage in spring 2017.  In particular, the inspectors
considered that PSEG's visual examinations of approximately 70 percent of the baffle bolts, in the fall 2015 refueling outage (2R21), did not identify any bolts that were 
18  missing or visually degraded.  Considering the collective results from Salem Unit 1 and 2 baffle bolt visual examination results, the inspectors determined this evidence, in conjunction with a review of other operating factors (EFPY and thermal cycles), provided
a reasonable expectation of the Salem Unit 2 baffle assembly's capability to perform its
supporting TS functions. 
Analysis. The inspectors determined that a performance deficiency resulted when PSEG did not implement Procedure OP-AA-108-115, "Operability Determinations &
Functionality Assessments," Section 4.7.14 followed by Sections 4.7.18-4.7.20 to
perform an OpEval to justify continued operation of the unit until the next refueling
outage for the Unit 2 baffle bolt degraded condition until questioned by NRC inspectors. 
PSEG's initial documentation did not provide sufficient basis for continued operation until the next refueling outage.  Specifically, based upon the Technical Evaluation 70187161 conclusion that the Salem Unit 2 design and operating life make it susceptible to baffle
bolt failures, the inspectors determined that PSEG, in effect, concluded that a degraded
condition exists in Unit 2.  Therefore, PSEG should have continued on in the operability
determination process as described in Section 4.7.14, "Operable but Degraded or Nonconforming." 
This finding is more than minor because it is associated with the equipment performance
attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences, in that, degradation of a significant number of baffle bolts could result in baffle plates dislodging following an accident.  This issue was dispositioned as more than minor because it was also similar to example 3.j of
IMC 0612, Appendix E, "Examples of Minor Issues," in that, the condition resulted in
reasonable doubt of operability of the ECCS and additional analysis was necessary to
verify operability.  In accordance with IMC 0609.04, "Initial Characterization of Findings," and Exhibit 2 of IMC 0609, Appendix A, "The Significance Determination Process for Findings At-Power," issued June 19, 2012, the inspectors screened the finding for safety
significance and determined it to be of very low safety significance (Green), since the
finding did not represent an actual loss of system or function.  After inspector
questioning, PSEG performed OpEval 2016-015, which provided sufficient bases to conclude the Unit 2 baffle assembly would support ECCS and control rod system operability until the next RFO.  This finding is related to the cross-cutting aspect of Operating Experience because PSEG did not effectively evaluate relevant internal and external operating experience.  Specifically, PSEG did not adequately evaluate the
impact of degraded baffle bolts at Unit 2 when directly relevant operating experience was identified at Unit 1. [P.5]  Enforcement. 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," states, in part, that activities affecting quality shall be prescribed by
documented procedures of a type appropriate to the circumstances and shall be
accomplished in accordance with those procedures.  The Introduction to Appendix B states that 'quality assurance' comprises all those planned and systematic actions necessary to provide adequate confidence that a SSC will perform satisfactorily in service.  PSEG Procedure OP-AA-108-115, "Operability Determinations & Functionality
Assessments," prescribes PSEG's process to assess the operability of SSCs that are
required to be operable by TSs, or that perform required support functions for SSCs that
are required to be operable by TSs.  Section 4.7 prescribes the operability determination process.  Section 4.7.14 states that if an SSC described in TSs is determined to be 
19  operable even though a degraded or nonconforming condition is present, then the SSC is considered "operable but degraded or nonconforming."  Sections 4.7.18 - 4.7.20 describe how the Operations Shift Manager should request the site engineering staff to
perform an "OpEval" upon a declaration of operable but degraded, or nonconforming. 
The OpEval is completed to justify continued operation during the period of time while
operable but degraded or nonconforming conditions exist.
Contrary to the above, from June 15, 2016, until July 26, 2016, PSEG did not accomplish actions necessary to provide adequate confidence that an SSC would
perform satisfactorily in service (an activity affecting quality) as prescribed by a documented procedure.  Specifically, although PSEG had concluded the Salem Unit 2
design and operating life make it susceptible to baffle former bolt failures, PSEG inadequately implemented Procedure OP-AA-108-115, to perform an OpEval to justify continued operation of the unit.  PSEG's corrective actions included entering the issue
into its corrective action program (NOTF 20736630) and documenting an adequate
operability evaluation (OpEval 2016-015 on July 26, 2016) to support the basis for
functionality of the baffle structure and its ability to support the operability of the ECCS and reactivity control systems.  This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy.  (NCV 05000311/2016002-02, Failure to Follow Operability Determination Procedure for Unit 2 Baffle-Former Bolts)  1R18 Plant Modifications (71111.18 - 2 samples)  .2 Permanent Modifications  a. Inspection Scope  The inspectors reviewed Design Change Package (DCP) 80117136, "Salem Unit 1 Baffle to Former Bolt Replacement.''  This modification documents the replacement of 189 degraded and potentially degraded baffle bolts with a new design baffle bolt made of
an improved material.  Additionally the modification documented the locations of the replacement bolts and the location of three degraded or potentially degraded bolts which
were left in place and are described below.  The inspectors also reviewed modification
documents (DCP 80117378) associated with the equivalency evaluation of the material change from Type 347 stainless steel to Type 316 stainless steel, and the bolt head design change from a slot to a hex configuration.  Thus this inspection involved two
samples - 1) the bolting pattern analysis for the replacement bolts, and 2) a review of
the bolting material change.
This modification was completed during the spring 2016 refueling outage (1R24) and involved the replacement of 189 baffle bolts out of a total of 832 located in the Unit 1
reactor vessel.  PSEG replaced 189 either degraded or potentially degraded baffle bolts
as observed by visual indications of missing or protruding bolt heads, missing or broken lock bar, bolts that did not pass ultrasonic testing or bolts that were inaccessible for
ultrasonic testing.  PSEG did not remove and replace three bolts that were potentially degraded due to difficulties encountered during the removal/replacement process.  One bolt had an indication during ultrasonic testing but was not visibly damaged.  The second
bolt was inaccessible for ultrasonic testing, which would have required replacement. 
The third bolt had successfully passed an ultrasonic test but had a visual indication on
one of the lock bar welds which may have indicated a crack in the weld.   
20  The inspectors reviewed PSEGs analysis and the Westinghouse minimum bolting analysis and determined that leaving the one degraded and two potentially degraded bolts installed was technically acceptable and that the baffle assembly was functional as
a system support component.  Details of the NRC assessment of the final configuration of the baffle bolts and the minimum bolting analysis can be found in Section 4OA2 of this
report.  b. Findings  No findings were identified. 
1R19 Post-Maintenance Testing (71111.19 - 9 samples)  a. Inspection Scope 
The inspectors reviewed the post-maintenance tests for the maintenance activities listed
below to verify that procedures and test activities adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure were consistent with the information in the applicable licensing basis
and/or design basis documents, and that the test results were properly reviewed and
accepted and problems were appropriately documented.  The inspectors also walked
down the affected job site, observed the pre-job brief and post-job critique where
possible, confirmed work site cleanliness was maintained, and witnessed the test or reviewed test data to verify quality control hold point were performed and checked, and that results adequately demonstrated restoration of the affected safety functions.
  Unit 1, 13 Station power transformer tap changer did not function in automatic on  May 4  Unit 1 11SJ45, residual heat removal (RHR) to SI motor-operated valve failure to stroke closed on May 5  Unit 1, 12 containment fan cooling unit (CFCU) motor cooler HX failed leak test on        May 6  Unit 1, Reactor coolant pump flow channel III degraded on May 6  Unit 1, Turbine-driven AFW room cooler cycling on May 10  Unit 1, Reactor vessel level indication system capillary repair on May 13  Unit 2, 24 SW strainer trip on thermal overloads on April 7  Unit 2, 24 SG flow channel 1 drop to 93 percent on May 4  Unit 2, 21 Chiller thermal expansion valve failure on May 24  b. Findings  No findings were identified. 
1R20 Refueling and Other Outage Activities (71111.20 - 1 sample)  a. Inspection Scope  The inspectors reviewed the station's work schedule and outage risk plan for the Unit 1
maintenance and refueling outage (1R24), conducted April 14 through the end of the
quarter.  The inspectors reviewed PSEGs development and implementation of outage 
21  plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered.  During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored controls
associated with the following outage activities:  Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable TSs when taking equipment out of service  Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated
work or testing  Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and instrument error accounting  Status and configuration of electrical systems and switchyard activities to ensure that TSs were met  Monitoring of decay heat removal operations  Impact of outage work on the ability of the operators to operate the SF pool cooling system  Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss  Activities that could affect reactivity  Maintenance of secondary containment as required by TSs  Refueling activities, including fuel handling and fuel receipt inspections  Fatigue management  Tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris had not been left which could block the emergency core cooling system suction strainers, and startup and ascension to full power operation  Identification and resolution of problems related to refueling outage activities  Foreign Object Search and Retrieval (FOSAR) for missing baffle bolts and locking tabs  During this outage, PSEG replaced 189 degraded baffle bolts in the Unit 1 reactor vessel
baffle assembly.  This emergent project resulted in the extension of the outage schedule from 36 days to 106 days.  b. Findings 
No findings were identified.
1R22 Surveillance Testing (71111.22 - 5 samples)  a. Inspection Scope 
The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and PSEG procedure requirements.  The inspectors verified that test acceptance criteria
were clear, tests demonstrated operational readiness and were consistent with design
documentation, test instrumentation had current calibrations and the range and accuracy
for the application, tests were performed as written, and applicable test prerequisites
were satisfied.  Upon test completion, the inspectors considered whether the test results 
22  supported that equipment was capable of performing the required safety functions.  The inspectors reviewed the following surveillance tests:  Unit 1, Manual SI on April 17  Unit 1, 11CA360, control air header supply check valve, as-found local leak rate test  (LLRT) on April 22  Unit 2, 21 RHR In-service Testing on April 1  Unit 2, 22SW223, SW outlet valve to 22 CFCU, stroke time in the required evaluation  range on May 3  Unit 2, Reactor coolant system (RCS) elevated leakrate on May 17  b. Findings  No findings were identified.  Cornerstone:  Emergency Preparedness  1EP6 Drill Evaluation (71114.06 - 1 sample) 
Emergency Preparedness Drill Observation  a. Inspection Scope 
The inspectors evaluated the conduct of a routine PSEG emergency drill on June 16 to identify any weaknesses and deficiencies in the classification, notification, and protective
action recommendation development activities.  The inspectors observed emergency response operations in the simulator, technical support center, and emergency operations facility to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures.  The
inspectors also attended the drill critique to compare inspector observations with those
identified by PSEG staff in order to evaluate PSEG's critique and to verify whether the
PSEG staff was properly identifying weaknesses and entering them into the CAP.    b. Findings  No findings were identified.  2.  RADIATION SAFETY  Cornerstones:  Occupational and Public Radiation Safety
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01 - 6 samples)  a. Inspection Scope  The inspectors reviewed PSEG's performance in assessing and controlling radiological hazards in the workplace.  The inspectors used the requirements contained in 10 CFR
Part 20, TSs, applicable Regulatory Guides (RGs), and the procedures required by TSs
as criteria for determining compliance. 
23    Inspection Planning  The inspectors reviewed the PIs for the occupational radiation safety cornerstone,
radiation protection (RP) program audits, and reports of operational occurrences in
occupational radiation safety since the last inspection.
Radiological Hazard Assessment (1 sample) The inspectors conducted independent radiation measurements during walk-downs of
the facility and reviewed the radiological survey program, air sampling and analysis, continuous air monitor use, recent plant radiation surveys for radiological work activities, and any changes to plant operations since the last inspection to verify survey adequacy of any new radiological hazards for onsite workers or members of the public. Instructions to Workers (1 sample) The inspectors reviewed high radiation area work permit controls and use; observed containers of radioactive materials and assessed whether the containers were labeled and controlled in accordance with requirements.  The inspectors reviewed several occurrences where a worker's electronic personal dosimeter alarmed.  The inspectors reviewed PSEG's evaluation of the incidents, documentation in the CAP, and whether compensatory dose evaluations were
conducted when appropriate.  The inspectors verified follow-up investigations of actual radiological conditions for unexpected radiological hazards were performed. Contamination and Radioactive Material Control  The inspectors observed the monitoring of potentially contaminated material leaving the radiological controlled area and inspected the methods and radiation monitoring instrumentation used for control, survey, and release of that material.  Radiological Hazards Control and Work Coverage (1 sample) The inspectors evaluated in-plant radiological conditions and performed independent radiation measurements during facility walk-downs and observation of radiological work
activities.  The inspectors assessed whether posted surveys; radiation work permits
(RWPs); worker radiological briefings and RP job coverage; the use of continuous air monitoring, air sampling, and engineering controls; and dosimetry monitoring were consistent with the present conditions.  The inspectors examined the control of highly
activated or contaminated materials stored within the SF pools and the posting and
physical controls for selected high radiation areas (HRAs), locked high radiation areas
(LHRAs) and very high radiation areas (VHRAs) to verify conformance with the occupational PI. Risk-Significant High Radiation Area and Very High Radiation Area Controls (1 sample) The inspectors reviewed the procedures and controls for HRAs, VHRAs, and radiological transient areas in the plant.   
24  Radiation Worker Performance and Radiation Protection Technician Proficiency  (1 sample)  The inspectors evaluated radiation worker performance with respect to RP work
requirements.  The inspectors evaluated RP technicians in performance of radiation
surveys and in providing radiological job coverage.    Problem Identification and Resolution (1 sample)  The inspectors evaluated whether problems associated with radiation monitoring and
exposure control (including operating experience) were identified at an appropriate
threshold and properly addressed in the CAP.  b. Findings  No findings were identified.  2RS2 Occupational As Low As is Reasonable Achievable Planning and Controls  (71124.02 - 3 samples)  a. Inspection Scope  The inspectors assessed PSEG's performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA).  The inspectors used the requirements contained in 10 CFR Part 20,
applicable RGs, TSs, and procedures required by TSs as criteria for determining
compliance.
  Inspection Planning  The inspectors conducted a review of Salem Station collective dose history and trends;
ongoing and planned radiological work activities; previous post-outage ALARA reviews;
radiological source term history and trends; and ALARA dose estimating and tracking procedures.  Radiological Work Planning  The inspectors selected the following radiological work activities based on exposure significance for review:
  RWP 13, Control Rod Drive Activities  RWP 14 , Pressurizer Activities  RWP 17, Primary SG Work  For each of these activities, the inspectors reviewed:  ALARA work activity evaluations; exposure estimates; and exposure reduction requirements.     
25    Verification of Dose Estimates and Exposure Tracking Systems  The inspectors reviewed the current annual collective dose estimate; basis methodology;
and measures to track, trend, and reduce occupational doses for ongoing work activities. 
The inspectors evaluated the adjustment of exposure estimates or re-planning of work.    Source Term Reduction and Control (1 sample) 
The inspectors reviewed the current plant radiological source term and historical trend,
plans for plant source term reduction, and contingency plans for changes in the source
term as the result of changes in plant fuel performance or changes in plant primary
chemistry.    The inspectors observed radiological work activities and evaluated the use of shielding
and other engineering work controls based on the radiological controls and ALARA plans
for those activities.    Radiation Worker Performance (1 sample)    The inspectors observed radiation worker and RP technician performance during
radiological work to evaluate worker ALARA performance according to specified work
controls and procedures.  Workers were interviewed to assess their knowledge and
awareness of planned and/or implemented radiological and ALARA work controls.    Problem Identification and Resolution (1 sample) 
The inspectors evaluated whether problems associated with ALARA planning and
controls were identified at an appropriate threshold and properly addressed in the CAP.  b. Findings  No findings were identified.
2RS3 In-Plant Airborne Radioactivity Control and Mitigation (71124.03 - 3 samples)  a. Inspection Scope  The inspectors reviewed the control of in-plant airborne radioactivity and the use of
respiratory protection devices in these areas.  The inspectors used the requirements in 10 CFR Part 20, RG 8.15, RG 8.25, NUREG/CR-0041, TS, and procedures required by TS as criteria for determining compliance.  Inspection Planning The inspectors reviewed the UFSAR to identify ventilation and radiation monitoring
systems associated with airborne radioactivity controls and respiratory protection equipment staged for emergency use.  The inspectors also reviewed respiratory protection program procedures and current PIs for unintended internal exposure
incidents.
   
26  Engineering Controls (1 sample)  The inspectors reviewed operability and use of both permanent and temporary
ventilation systems, and the adequacy of airborne radioactivity radiation monitoring in the plant based on location, sensitivity, and alarm set-points. 
Use of Respiratory Protection Devices (1 sample) 
The inspectors reviewed the adequacy of PSEG's use of respiratory protection devices in the plant to include applicable ALARA evaluations, respiratory protection device
certification, respiratory equipment storage, air quality testing records, and individual
qualification records.  Problem Identification and Resolution (1 sample) The inspectors evaluated whether problems associated with the control and mitigation of
in-plant airborne radioactivity were identified at an appropriate threshold and addressed by PSEG's CAP.  b. Findings  No findings were identified. 
2RS4 Occupational Dose Assessment (71124.04 - 2 samples)  a. Inspection Scope  The inspectors reviewed the monitoring, assessment, and reporting of occupational dose.  The inspectors used the requirements in 10 CFR Part 20, RGs, TSs, and
procedures required by TSs as criteria for determining compliance.   
Inspection Planning  The inspectors reviewed:  RP program audits; National Voluntary Laboratory
Accreditation Program (NVLAP) dosimetry testing reports; and procedures associated with dosimetry operations.
Source Term Characterization (1 sample)  The inspectors reviewed the plant radiation characterization (including gamma, beta,
alpha, and neutron) being monitored.  The inspector verified the use of scaling factors to
account for hard-to-detect radionuclides in internal dose assessments.
External Dosimetry  The inspectors reviewed: dosimetry NVLAP accreditation; onsite storage of dosimeters;
the use of "correction factors" to align electronic personal dosimeter results with NVLAP
dosimetry results; dosimetry occurrence reports; and CAP documents for adverse trends related to external dosimetry. 
 
27  Internal Dosimetry (1 sample)  The inspectors reviewed:  internal dosimetry procedures; whole body counter measurement sensitivity and use; adequacy of the program for whole body count
monitoring of plant radionuclides or other bioassay technique; adequacy of the program
for dose assessments based on air sample monitoring and the use of respiratory
protection; and internal dose assessments for any actual internal exposure.  Special Dosimetric Situations  The inspectors reviewed external dose monitoring of workers in large dose rate gradient
environments.    Problem Identification and Resolution  The inspectors evaluated whether problems associated with occupational dose assessment were identified at an appropriate threshold and properly addressed in the CAP.  b. Findings  No findings were identified.  2RS5 Radiation Monitoring Instrumentation (71124.05 - 1 sample)  a. Inspection Scope  The inspectors reviewed performance in assuring the accuracy and operability of radiation monitoring instruments used to protect occupational workers during plant operations and from postulated accidents.  The inspectors used the requirements in
10 CFR Part 20; RGs; applicable industry standards; and procedures required by TSs as criteria for determining compliance. Inspection Planning The inspectors reviewed: Salem Station UFSAR; RP audits; records of in-service survey instrumentation; and procedures for instrument source checks and calibrations.  Walkdowns and Observations  The inspectors checked the calibration and source check status of various portable
radiation survey instruments and contamination detection monitors for personnel and
equipment.  Calibration and Testing Program 
The inspectors reviewed the calibration standards used for portable instrument
calibrations and response checks to verify that instruments were calibrated by a facility that used National Institute of Science and Technology traceable sources. 
 
28    Problem Identification and Resolution (1 sample)  The inspectors verified that problems associated with radiation monitoring
instrumentation (including failed calibrations) were identified at an appropriate threshold
and properly addressed in the CAP. 
b. Findings  No findings were identified.  Cornerstone:  Public Radiation Safety (PS) 
2RS7 Radiological Environmental Monitoring Program (71124.07 - 2 samples)  a. Inspection Scope  The inspectors reviewed the Radiological Environmental Monitoring Program (REMP) to validate the effectiveness of the radioactive gaseous and liquid effluent release program and implementation of the Groundwater Protection Initiative (GPI).  The inspectors used
the requirements in 10 CFR Part 20; 40 CFR Part 190; 10 CFR Part 50, Appendix I; TSs;
Offsite Dose Calculation Manual (ODCM); Nuclear Energy Institute 07-07; and
procedures required by TSs as criteria for determining compliance.
  Inspection Planning  The inspectors reviewed:  Salem and Hope Creek Station's 2015 annual radiological environmental and effluent monitoring reports; REMP program audits; ODCM changes; land use census; UFSAR; and inter-laboratory comparison program results.  Site Inspection (1 sample)  The inspectors walked down various passive dosimeter and air and water sampling
locations and reviewed associated calibration and maintenance records.  The inspectors
observed the sampling of various environmental media as specified in the ODCM and reviewed any anomalous environmental sampling events including assessment of any positive radioactivity results.  The inspectors reviewed any changes to the ODCM.  The inspectors verified the operability and calibration of the meteorological tower instruments
and meteorological data readouts.  The inspectors reviewed environmental sample
laboratory analysis results, laboratory instrument measurement detection sensitivities, laboratory quality control program audit results, and the inter- and intra-laboratory comparison program results.  The inspectors reviewed the groundwater monitoring
program as it applies to selected potential leaking structures, systems, or components; and 10 CFR 50.75(g) records of leaks, spills, and remediation since the previous
inspection.  Groundwater Protection Initiative Implementation The inspectors reviewed:  groundwater monitoring results; changes to the Groundwater Protection Initiative (GPI) program since the last inspection; anomalous results or
missed groundwater samples; leakage or spill events including entries made into the decommissioning files (10 CFR 50.75 (g)); evaluations of surface water discharges; and 
29  PSEG's evaluation of any positive groundwater sample results including appropriate stakeholder notifications and effluent reporting requirements.   
Identification and Resolution of Problems (1 sample)  The inspectors evaluated whether problems associated with the REMP were identified at
an appropriate threshold and properly addressed in PSEG's CAP.    b. Findings  No findings were identified.  4. OTHER ACTIVITIES  4OA1 Performance Indicator Verification (71151) 
Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with Complications (6 samples)  a. Inspection Scope  The inspectors reviewed PSEG submittals for the following Initiating Events Cornerstone PIs for the period of July 1, 2015 through June 30, 2016.    Unit 1 & 2 Unplanned Scrams  Unit 1 & 2 Unplanned Power Changes  Unit 1 & 2 Unplanned Scrams with Complications  To determine the accuracy of the PI data reported during those periods, inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02,
"Regulatory Assessment Performance Indicator Guideline," Revision 7.  The inspectors
reviewed PSEG operator narrative logs, maintenance planning schedules, condition
reports, event reports, and NRC integrated IRs to validate the accuracy of the submittals.  b. Findings  No findings were identified.
4OA2 Problem Identification and Resolution (71152 - 4 samples)  .1 Routine Review of Problem Identification and Resolution Activities  a. Inspection Scope  As required by Inspection Procedure 71152, "Problem Identification and Resolution," the
inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify PSEG entered issues into their CAP at an appropriate threshold,
gave adequate attention to timely corrective actions, and identified and addressed adverse trends.  In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily 
30  screening of items entered into their CAP and periodically attended condition report screening meetings.  The inspectors also confirmed, on a sampling basis, that, as applicable, for identified defects and non-conformances, PSEG performed an evaluation
in accordance with 10 CFR Part 21.  b. Findings  No findings were identified. 
.2 Semi-Annual Trend Review  a. Inspection Scope  The inspectors performed a semi-annual review of site issues to identify trends that
might indicate the existence of more significant safety concerns.  As part of this review, the inspectors included repetitive or closely-related issues documented by PSEG in the
CAP and repetitive or closely-related issues that may have been documented by PSEG outside of the CAP, such as trend reports, PIs, major equipment problem lists, system health reports, MR assessments, and maintenance or CAP backlogs.  The inspectors
also reviewed PSEG CAP database for the first and second quarters of 2016 to assess notifications written in various subject areas (equipment problems, human performance issues, etc.), as well as individual issues identified during the inspector's daily condition report review (Section 4OA2.1).  The inspectors reviewed the PSEG CAP trending data, conducted under LS-AA-125, to verify that PSEG personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.
a. Findings and Observations  No findings were identified. 
Equipment Reliability (Steady)  The inspectors documented an adverse trend in either equipment reliability or unplanned entries into TS shutdown limiting conditions for operation (LCO) in each of the previous
four semi-annual trend review periods (IRs 05000272; 311/2014003, 2014005, 2015002
and 2015004).  In February 2016, in response to PSEG's unplanned LCO performance
goal not being met, PSEG performed Common Cause Evaluation (CCE) 70184208, Unplanned Shutdown LCO Goal Not Met.  The CCE was completed in April of 2016, with the following results:
  A trend of data over an 18-month period from August 2014 through January 2016 identified 68 unplanned shutdown LCOs, which far exceeded the station goal of no more than 8 in a 12-month rolling average.  PSEG's CCE concluded:
1) 15 LCO entries were attributed to faulty parts; 2) 10 entries were attributed to equipment not being repaired in a timely manner; and 3) more follow up evaluations were warranted:  o Work Group Evaluation (WGE) 70185245, "Follow up Evaluation from Unplanned shutdown LCOs," was performed to further evaluate the
10 entries attributed to equipment not being repaired in a timely manner.  PSEG attributed the cause to ineffective development and 
31  implementation of equipment reliability strategies to ensure reliability until long-term elimination or mitigating actions were in place.  Actions were assigned to develop bridging strategies for Plant Health Committee items
and rollout to Station Oversight Committee (SOC) and Management
Review Committee (MRC) an expectation that if an unplanned LCO
occurs, a causal evaluation should be performed. 
The inspectors noted some improvement in the area of unplanned entries into TS LCOs in recent months; specifically, 44 unplanned shutdown LCOs occurred from June 2015
to April 2016, but only seven occurred in the last 3 months of this 10 month period.  The
inspectors determined that the adverse trend of equipment failures did not constitute a
performance deficiency, because the trend, by itself, did not constitute a violation of any NRC requirement.  The inspectors inspected individual equipment failures as ROP baseline inspection samples documented in other sections of this report. 
Main Control Room Deficiencies (Steady with recent improvement)  The inspectors noted an adverse trend in main control room deficiencies, as evident by a Red station performance metric dating back to mid-2015, when the station metric was
redefined to align with the current industry metric.  Specifically, in June of 2016, Unit 1
had 69 and Unit 2 had 45, versus a red performance metric threshold of 16 or more. 
However, the inspectors noted recent improvements in this area.  Specifically, Unit 1
reduced the backlog from 99 in January 2016 to 69 in June, and Unit 2 reduced the backlog from 73 before the fall 2015 refueling outage to 45 in June 2016. 
Untimely Reportability Determinations (Steady) 
In Section 4OA2.2 of IR 2015-004, the inspectors identified that past operability determinations were untimely in supporting conclusions of LER reportability in 60 days, and listed multiple examples.  In response to a LER 05000311/2016-001-000 being
submitted well beyond 60 days from the occurrence of the event (see Sections 4OA2.3 and 4OA7 of this report), PSEG performed a review under apparent cause evaluation
(ACE) 70183590, to determine the extent of condition relative to "missed or late" reports
under 10 CFR 50.72 and 50.73.  PSEG concluded the following:  1) The execution of CAP does not support timely completion of evaluation products to support 60-day LER submittals; 2) SOC and MRC have a low threshold for requesting reportability reviews;
and 3) Salem has a high number of supplemental LERs relative to the industry (four in
2015 versus an industry average of less than one), indicating that CAP does not support
timely cause evaluation completion, which require LERs to be supplemented.  The inspectors noted that PSEG's conclusion 3 above is consistent with a previously identified trend by the inspectors documented in Section 4OA2.2 of IR 2015002, which
listed a steady increase in CAP evaluation products and subsequent trend of CAP
products falling behind station timeliness goals.  As a result of the ACE listed above,
PSEG issued a temporary standing order to develop interim guidance until process improvements and controls were institutionalized for reportability, assigned corrective actions to develop procedure improvements and controls for accompanying reportability reviews, and to develop the appropriate change management plan for process changes
to perform reportability reviews.  The inspectors did not identify any actual violations of
10 CFR 50.72 or 50.73 during the performance of this inspection.  The timeliness of
reportability determinations remains a minor adverse trend. 
32  Status Control and Human Performance Events (Improving)  The inspectors previously documented an adverse trend in status control in Section
4OA2.5 of IR 2014005.  In December of 2015, Nuclear Oversight identified an adverse
trend in status control.  In February of 2016, PSEG completed a CCE in response to the
adverse trend in plant status control.  Additionally, status control was a focus area for the
station in 2016.  Since that time, the inspectors noted considerable improvement in the area of status control.  Specifically, as of June 1, 2016, the station achieved 181 status control event free days.  However, in recent months, the inspectors noted several human
performance events that were not classified as status control events, though they reflect
many of the same behavioral breakdowns in standards and fundamentals.  Examples
include:  April 17:  1B EDG invalid actuation:  During the performance of solid state protection system testing in Mode 6 (refueling), the 1B EDG unexpectedly started while an operator in the field was attempting to replace a light bulb on the test
box.  PSEG performed an investigation and determined that the most likely
cause was due to the operator's finger bumping the block switch during the bulb
replacement, which was enough pressure to allow the test block signal to be momentarily interrupted.  PSEG reported this event as a telephone notification under 10 CFR 50.73(a)(1) and (a)(2)(iv)(A) on June 15.
  April 25:  #1 Emergency Compressed Air Compressor trip during leak test - PSEG performed Quick Human Performance Investigation (QHPI) 70186240 and determined the operator in the control room did not understand the report from
the equipment operator in the field, and determined that three-way
communication was not used when it should have been.  April 19:  22B circulator bypass valve operated in the wrong direction - PSEG performed QHPI 71085972 and determined that an equipment operator did not fully open the 22B circulator outlet valve prior to attempting remote closure of the
22B circulator bypass, which resulted in the bypass valve failing to stroke closed.    March 27:  Station Blackout (SBO) air compressor tripped - the equipment operator did not follow procedure while testing the SBO air compressor, resulting in a trip of the compressor (20723821).  The inspectors determined that none of the issues above were of more than minor
significance, because none of them resulted in a significant plant transient or loss of a mitigating system.  The inspectors determined that although the trend in events
classified as status control had improved, the behaviors that contributed to them were still present. 
.3 Annual Sample:  Unit 2 Auxiliary Feedwater Loop Response Time Exceeded Technical Specifications  a. Inspection Scope  The inspectors performed an in-depth review of PSEG's identification, evaluation, and resolution following the discovery that a channel of the 21 AFW pump engineered
safety feature actuation system (ESFAS) automatic actuation logic was inoperable. 
33  On November 18, 2015, maintenance personnel compiling test data, collected on October 18, 2015, during the Unit 2 plant shutdown for the fall 2015 refueling outage, determined that the pump instrumentation loop time response exceeded test acceptance
criteria.  At the time, Unit 2 was shut down in a refueling outage and AFW was not
required.  The cause of the slow loop response was due to the isolation valve to the
21 AFW pump discharge pressure transmitter (2PA3450) being closed.  The pressure
transmitter provided input into the pump run-out protection and flow control circuit.  The closed isolation valve caused the pressure transmitter to take longer to sense pump discharge pressure, which resulted in the slow opening of the pump SG flow control
valves (valves 23AF21 and 24AF21).  PSEG's investigation determined that the
condition likely existed since April 20, 2015, following the completion of maintenance on
the pressure transmitter.  On January 19, 2016, PSEG determined that the condition was reportable to the NRC.  PSEG initiated an ACE to determine the cause of the untimely review and evaluation of the surveillance data collected on October 18, 2015,
and a WGE to determine the cause of the improperly positioned isolation valve to
pressure transmitter 2PA3450.  The inspectors performed an in-depth review of the ACE
and WGE and corrective actions associated with the issues documented in Orders 70183590 and 70182519.  PSEG submitted Licensee Event Report (LER) 05000311/2016-001-000, "AFW Loop Response Time Exceeded TSs," on March 21,
2016, as an operation or condition which was prohibited by the plant's TS.  The
inspectors' review of the LER is documented in Section 4OA3.1 of this report.  Section
4OA7 documents the enforcement aspects related to the LER.
The inspectors assessed PSEG's problem identification threshold, causal analysis, extent of condition reviews, compensatory actions, and the prioritization and timeliness
of corrective actions to determine whether PSEG was appropriately identifying,
characterizing, and correcting problems associated with these issues and whether the
planned or completed corrective actions were appropriate.  The inspectors compared the actions taken to the requirements of PSEG's CAP and 10 CFR Part 50, Appendix B.  In addition, the inspectors reviewed documentation associated with this issue, and
interviewed engineering and maintenance personnel to assess the effectiveness of
the implemented and planned corrective actions. 
b. Findings and Observations 
No findings were identified.
Maintenance personnel compiling 21 AFW pump loop time response test data identified
the slow response times for valves 23AF21 and 24AF21, and entered this issue into the CAP as NOTF 20710947.  During their review, PSEG identified that the instrument isolation valve for the 21 AFW pump discharge pressure transmitter (2PA3450) was
closed versus the required position of open.  The improperly positioned valve was
promptly placed into the required open position.  PSEG entered the improperly positioned valve into the CAP as NOTF 20709417, and performed a prompt investigation
and a WGE.  The inspectors determined that action taken by PSEG upon discovery of the slow response times for valves 23AF21 and 24AF21 were prompt and appropriate. 
The inspectors reviewed Order 70182519, which documented the WGE for instrument
isolation valve for 2PA3450 being found in the incorrect position.  Although the actual
cause of the improperly positioned isolation valve was indeterminate, PSEG concluded that the condition most likely existed since April 20, 2015, when maintenance was last 
34  performed on 2PA3450.  Corrective actions included plans to install human factors tools (i.e., additional measure devices) on all transmitter isolation valves located in both the Unit 1 and 2 AFW instrumentation panels.  The inspectors concluded that PSEG's
planned corrective action was appropriate.    The inspectors reviewed the timeline of events from the collection of test data on
October 18, 2015, until the submittal of the LER for the condition prohibited by TS related to the slow instrument loop response time for the 21 AFW pump.  The inspectors concluded that information was available to PSEG personnel on November 20, 2015,
that the condition was potentially reportable when the cause was determined to be due
to the incorrectly positioned instrument isolation valve to 2PA3450.  However, the
required LER was not submitted until March 21, 2016.    The inspectors reviewed PSEG's investigation into the reportability timeliness issue, as
documented in Order 70183590.  PSEG determined that the cause was due to work
tracking assignments not being made to facilitate identification and completion of the required past operability review in accordance with Engineering standard practice.  The normal practice to evaluate issues for potential past operability/reportability is for the SOC to assign a 'technical evaluation' to Engineering to review.  In this case an 'action
item' was assigned to Engineering versus a 'technical evaluation'.  The due dates for
'action items' are allowed to be extended by the assignee whereas, the process of
extending 'technical evaluations' has more stringent controls.  Therefore, the priority of
the 'action item' was not established at the correct threshold by the assigned engineering supervisor.  This resulted in extensions of the due date for the past operability/reportability review.  PSEG's corrective actions taken or planned included
issuance of an Operations standing order, which provided additional interim guidance for
performing past operability and reportability reviews, and to develop process
improvements and controls for accomplishing past operability and reportability reviews.  The inspectors concluded that the actions taken or planned appeared to appropriately address the reportability timeliness issue.  In accordance with IMC 0612, "Power
Reactor Inspection Reports," the above timeliness of reportability issue constituted a
violation of minor significance that is not subject to enforcement action in accordance
with the Enforcement Policy.
As discussed in Order 70183590, PSEG recognized that the SOC inappropriately assigned an 'action item' versus the more appropriate 'technical evaluation' to
Engineering for the past operability/reportability review.  The inspectors observed that
actions taken by PSEG did not directly address the shortfall of the SOC in this case. 
The inspectors noted that there was a low level assignment for the SOC to evaluate for a human performance crew clock reset; however, the clock reset was determined to not be necessary.  The inspectors noted that the other actions taken or planned discussed
above appeared to be adequate to address the inappropriate extensions of past
operability and reportability reviews. 
In NRC Inspection Report 05000272, 05000311/2015004, dated February 10, 2016, a problem identification and resolution adverse trend was documented related to past operability determinations being untimely in supporting conclusions of LER reportability
within sixty days.  The inspectors concluded that the untimely past operability and
reportability review of the failed 21 AFW pump instrument loop time response test as an
additional example of the adverse trend identified in NRC IR 05000272, 
35  05000311/2015004 and updated in Section 4OA2.2 of this report.  At the end of this inspection period, PSEG had not entered this adverse trend into their CAP. 
.4 Annual Sample:  Struthers-Dunn Relay Failures in Safety-Related Applications  a. Inspection Scope  The inspectors performed an in-depth review of PSEG's ACE and corrective actions associated with NOTF 20681569 related to a 21 containment spray (CS) pump failure to
start.  The 21 CS pump failed to start on October 2, 2015, during post-maintenance
testing following scheduled maintenance.  The 21 CS pump failure to start was
investigated by PSEG during subsequent troubleshooting.  Additionally, a failure modes and causal table determined the most likely cause for the failure to start was from a starting relay high contact resistance.  PSEG postulated that contact contamination created a high resistance condition that was subsequently cleared due to the wiping
action of the relay contact.  The starting relay was a Struthers-Dunn Model 219BBX-240
and was replaced.  The failed relay was sent for failure analysis to an offsite laboratory.  The lab was unable to repeat the high resistance contact operation that was observed at Salem.  The lab functional testing did not yield any deficiencies or failure mechanisms. 
The inspectors assessed PSEG's problem identification threshold, causal analyses, technical analyses, extent of condition reviews, and the prioritization and timeliness of
corrective actions to determine whether PSEG was appropriately identifying, characterizing, and correcting problems associated with this issue.  The inspectors reviewed the circumstances of this relay failure issue to ascertain the appropriateness of
corrective actions.  The inspectors also assessed PSEG's corrective actions to prevent recurrence.  The inspectors compared the actions taken to the requirements of PSEG's CAP and 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action.  In addition, the inspectors reviewed documentation associated with this issue, including condition reports, and interviewed engineering personnel to assess the effectiveness of the
planned and implemented corrective actions.
b. Findings and Observations  No findings were identified.   
The Struthers-Dunn relays in critical applications were all replaced in 1996 and 1997
during extended unit shutdowns.  From about 2000 to 2015, Salem experienced
Struthers-Dunn relay failures in critical applications at about one MR functional failure per year.  In May 2013, after a Struthers-Dunn relay failure associated with the 15 containment fan cooling unit (CFCU), PSEG developed extensive corrective actions to revise preventive maintenance (PM) templates and determine an appropriate
replacement periodicity.  An accelerated testing program was a corrective action and
completed in March 2014 to determine the number of relay operations when the contacts
gold flashing began to wear away exposing the silver base.  Exposing the silver contact base leads to a corrosion condition called sulfidation creating a high resistance between relay contacts.  Offsite laboratory analysis of previous Struthers-Dunn relays had
identified worn gold flashing and sulfidation.
PSEG determined from the accelerated relay testing program that Struthers-Dunn relays in CFCU applications should be replaced every 10 years.  The CFCUs have more 
36  frequent equipment on/off cycles compared to other critical Struthers-Dunn applications.  PSEG determined all other Struthers-Dunn relay replacements should be replaced at 20 years.  PSEG established the 20 year replacement interval based on 400 relay operations for the equipment considered.  However, the inspectors noted that for some
relay applications, major gold flashing wear or wiping resulting in areas of exposed silver
was observed from the accelerated failure testing results at just 350 relay operations. 
PSEG generated notification 20734284 in response to the inspectors' observation for resolution and to reevaluate the intended 20 year replacement periodicity.   
The corrective action due dates for the final PM templates are due in August 2016. 
PSEG accelerated and completed the Struthers-Dunn relay replacements in all CFCU
applications.  The inspectors noted that if PSEG finalizes a 20 year replacement for non-CFCU applications, considering that all Struthers-Dunn relays were replaced in 1996 to 1997, then all Struthers-Dunn relays would now or in the near term require
replacement.  PSEG initiated notification 20734280 in response to the inspectors' observation for resolution.    .5 Annual Sample:  Unexpected Number of Degraded Baffle-Former Bolts Discovered in the Unit 1 Reactor Pressure Vessel  a. Inspection Scope  The inspectors performed an in-depth review of PSEG's technical evaluation and corrective actions associated with NOTF 20726264 for baffle-former ("baffle") bolts found with indications of degradation during the spring 2016 Salem Unit 1 24th refueling outage (1R24).  PSEG performed ultrasonic examinations of the baffle bolts in accordance with their procedures in response to recent industry operating experience and 1R24 visual
examination results indicating 18 visually damaged baffle bolts.  After an unexpected number of degraded baffle bolts were discovered, PSEG staff entered the issue into their corrective action program as NOTF 20727538 and reported the issue to the NRC as
Event Notification No. 51902 on May 3, 2016, because the as-found number and
location of degraded bolts, which were mainly concentrated in three of the eight baffle
assemblies, represented an unanalyzed condition.  PSEG staff completed corrective
actions to replace 189 of 192 potentially degraded baffle bolts on Unit 1.  As documented in Section 1R18, PSEG did not remove and replace three bolts that were potentially degraded due to difficulties encountered during the removal/replacement
process.   
The baffle bolts help secure vertical plates (also referred to as baffle plates) inside the reactor vessel, which then forms a structure surrounding the reactor fuel assemblies to orient the fuel and to direct coolant flow through the core.  A sufficient number of baffle
bolts are required to remain intact to secure the baffle plates in place so as to not affect
control rod insertion or impede emergency core cooling flow during postulated accident
conditions. Bolt heads that separate and are no longer held in place by bolt lock-tabs
can also become a loose parts concern.  The inspectors assessed whether PSEG acceptable baffle bolt pattern analysis for
Unit 1 was completed in accordance with the NRC-approved methodology and provided
appropriate structural margin for the next cycle of operation to ensure the Unit 1 baffle
plates will remain in place during both normal operation and limiting postulated accident conditions.  The inspectors also assessed whether PSEG's evaluations of the baffle 
37  bolts installed in Salem Unit 2 were technically sufficient to conclude the Unit 2 baffle assembly will perform as intended until the next planned refueling outage, at which time PSEG plans to examine the bolts.  The inspectors reviewed PSEG's procedures for
determining the functionality and operability of degraded systems, components and
structures as they relate to Unit 2.  Additionally, the inspectors interviewed PSEG engineering personnel and contractor staff to discuss the results of PSEG's technical evaluations and to assess the effectiveness of the implemented and planned corrective actions. 
The inspectors assessed PSEG's problem identification threshold, cause analyses, extent of condition, compensatory actions, and the prioritization and timeliness of
PSEG's corrective actions to determine whether PSEG staff were properly identifying, characterizing, and correcting problems associated with this issue and whether the planned or completed corrective actions were appropriate.  The inspectors compared the
actions taken to PSEG's corrective action program, operability determination process, and the requirements of 10 CFR Part 50, Appendix B.  The inspectors observed portions
of baffle bolt replacement activities at Unit 1 and reviewed the final visual examination of the baffle bolts and plates once the work was completed.  b. Observations 
The NRC responded to the initial discovery of an unexpected number of baffle bolts
found degraded at Salem Unit 1 by implementing a comprehensive inspection plan consisting of various baseline inspection samples to assess the extent of the issue and to determine the necessary NRC actions.  A previously planned ISI sample (Refer to
Section 1R08) was expanded to include a review of the capability of the NDE techniques
for ultrasonically testing (UT) the baffle bolts, to evaluate the UT results, and to observe
a portion of bolt replacement activities on-site.  Two permanent modification samples (Refer to Section 1R18) were conducted to review the design change package and evaluations associated with the new, replacement baffle bolts, and to review the PSEG
design change package documenting the as-left baffle bolting pattern in Unit 1.  NRC
resident inspectors reviewed PSEG's foreign material controls and loose parts analysis (Refer to Section 1R20) to address the potential for missing bolt heads and concluded it
would not impact safe operation of the plant.  NRC Region I based inspectors, accompanied by an expert from the NRC Office of Nuclear Reactor Regulation, completed this annual problem identification and resolution
inspection sample, to verify that PSEG's evaluations and corrective action to replace Unit 1 baffle bolts were completed in accordance with NRC approved methodology to support a conclusion that the Unit 1 baffle assembly meets the plant design basis.  The inspectors also reviewed the adequacy of PSEG's technical evaluations completed to
determine whether there is a reasonable expectation the Unit 2 baffle assembly will
perform as intended during the current operating cycle.  The results of this review are discussed herein and in Section 1R15 of this report.
At the completion of this inspection, PSEG's conduct of a RCE to determine the causes of the failure of the baffle bolts in Unit 1 was ongoing.  The inspectors determined
PSEG's RCE will not be completed until after laboratory tests and analyses, planned for fall 2016, are performed on a sample of the bolts removed from Unit 1.  PSEG's
technical evaluation discussed the cause of the degraded baffle bolts as primarily due to IASCC.  This determination was based on industry operating experience related to baffle 
38  bolt failure in both foreign and domestic plants, is a known degradation mechanism and the operational and physical characteristics of both Salem plants indicate that they are susceptible to this mechanism.  The inspectors reviewed PSEG's technical evaluation and the supporting operating experience related to baffle bolt failures at other plants. 
IASCC is a cracking mechanism that occurs over a long period of time when susceptible
metals are exposed to neutron radiation from the reactor core and stresses as part of
normal design and operation.  The inspectors determined PSEG identified the likely cause of the baffle bolt degradation and their plans to complete a RCE when additional metallurgical information was available was appropriate. 
Following identification of the degraded baffle bolts on Unit 1, PSEG's immediate corrective action was to analyze the as-found condition and begin replacing bolts that either had visual indications of bolt failure (protruding bolt head for example), did not pass UT examination, or were not accessible for UT examination.  The as-found number
and pattern of these bolts exceeded the acceptance criteria in the plant's analysis that
was prepared in advance of the baffle bolt examinations; therefore, PSEG reported this
discovery to the NRC as an unanalyzed condition in Event Notification 51902 on May 3, 2016.  PSEG staff completed corrective actions to replace 189 of 192 potentially degraded baffle bolts.  PSEG did not remove and replace three bolts that were
potentially degraded due to difficulties encountered during the removal/replacement
process.  As previously documented in Section 1R18, one bolt had an indication during
ultrasonic testing but was not visibly damaged.  The second bolt was inaccessible for
ultrasonic testing, which would have required replacement.  The third bolt had successfully passed an ultrasonic test but had a visual indication on one of the lock bar welds which may have indicated a crack in the weld. 
The inspectors determined that PSEG staff performed an acceptable bolt pattern
analysis that evaluated the replacement bolt pattern for Unit 1.  The inspectors found the results of the analysis accounted for a conservative failure rate of bolts and provided appropriate margin for one cycle of operation.  The inspectors verified that PSEG's
methodology for its acceptable bolt pattern analyses, including its determination of
margin, was consistent with the NRC-approved methodology in topical report
WCAP-15029-NP-A (ML15222A882).  The inspectors determined that PSEG staff
tracked corrective actions to re-examine the Unit 1 baffle bolts during the next planned refueling outage.  The inspectors noted the new baffle bolts were made of a material (316 SS) with improved resistance to IASCC and included an improved design to reduce the stresses at the head to shank transition, both of which are enhancements compared
to the original bolts.
As part of an extent of condition assessment, PSEG entered NOTF 20727590 in its corrective action program to evaluate the potential for degraded baffle bolts on Unit 2. 
PSEG operators performed an IOD and concluded that the baffle assembly was operable.  PSEG staff performed a subsequent technical evaluation that concluded
Unit 2 would experience less baffle bolt degradation than Unit 1 based on several plant
factors.  The inspectors reviewed PSEG's technical evaluations, including the inputs for the operability determination, and noted that PSEG staff concluded there was not a degraded condition at Unit 2.  In consideration of the guidance in PSEG's operability
procedure and operating experience from Unit 1 and other plants, the NRC issued an
NCV in this report because PSEG did not perform an OPEval for Unit 2 as a follow-up to
the IOD for the potential impact on supported systems controlled by the Technical Specifications (Refer to Section 1R15). 
39  As a corrective action, PSEG staff performed OpEval 2016-015 and demonstrated that the Unit 2 baffle assembly remained operable.  The inspectors concluded that this supplemental evaluation provided adequate technical justification for the continued
operation of Unit 2 until the next refueling outage in spring 2017, at which time PSEG
plans to examine the baffle bolts.  PSEG also implemented compensatory measures to monitor the reactor coolant system for any signs of fuel leakage, which could be an indicator of baffle bolt failures and to generate additional contingency actions in response to indications of increased unidentified leakage or receipt of a metal impact monitoring system alarm.
The inspectors reviewed Westinghouse Nuclear Safety Advisory Letter NSAL-16-1,
which discussed the results of recent baffle bolt inspections and provided Westinghouse's recommendations on this issue.  The letter described the plants as most susceptible (i.e. Tier 1a) to this degradation as Westinghouse 4-loop reactors limited to
those with a down-flow configuration and using Type 347 stainless steel.  A non-
proprietary presentation on the contents of NSAL-16-1 can be found at ML16202A063.
The inspectors noted the recommendation was to complete UT volumetric examination of the baffle bolts at the next scheduled refueling outage, and that PSEG had already planned this action for Unit 2.  The inspectors determined PSEG's overall response to
the issue was commensurate with the safety significance, was timely, and included
appropriate compensatory actions.  The inspectors concluded that the actions completed
and planned were reasonable to address the ongoing aging management of baffle bolts.  4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153 - 4 samples)  .1 Plant Events (2 samples) 
      a.  Inspection Scope  For the plant events listed below, the inspectors reviewed and/or observed plant
parameters, reviewed personnel performance, and evaluated performance of mitigating
systems.  The inspectors communicated the plant events to appropriate regional
personnel, and compared the event details with criteria contained in IMC 0309, "Reactive
Inspection Decision Basis for Reactors," for consideration of potential reactive inspection activities.  As applicable, the inspectors verified that PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR
50.72 and 50.73.  The inspectors reviewed PSEGs follow-up actions related to the
events to assure that PSEG implemented appropriate corrective actions commensurate
with their safety significance.  Unit 1, Baffle to former bolts found broken or degraded on May 3  (EN 51902)  Unit 2, Reactor trip from main turbine trip on June 28  (EN 52048)        b.  Findings  No findings were identified.   
 
40  .2 (Closed) LER 05000311/2016-001-000:  Auxiliary Feedwater Loop Response Time Exceeded Technical Specifications   
      a. Inspection Scope  While evaluating surveillance instrumentation loop time response test data associated
with the 21 AFW pump that was collected during the Unit 2 plant shutdown for the fall 2015 refueling outage, PSEG determined that a channel of the pump's ESFAS automatic actuation logic was inoperable.  In November 2015, PSEG personnel
identified the slow loop response time during surveillance testing.  The cause of the slow
loop response was due to the isolation valve to the 21 AFW pump discharge pressure
transmitter (2PA3450) being closed.  The pressure transmitter provided input into the pump run-out protection and flow control circuit.  The closed isolation valve caused the pressure transmitter to take longer to sense pump discharge pressure which resulted in
slow opening of the pump steam generator flow control valves (valves 23AF21 and 24AF21).  PSEG's investigation determined that the condition existed since April 20,
2015, following the completion of maintenance on the pressure transmitter.  An engineering review concluded that, although the AFW loop response time test results did not satisfy TS requirements, the accident analysis assumptions remained valid and the
condition did not result in an unanalyzed condition.  This issue is discussed in more
detail in Section 4OA2.1 of this report.  No other issues were identified during the review
of the LER.  This LER is closed. 
      b.  Findings  The enforcement aspects of this violation are discussed in Section 4OA7.  .3 (Closed) LER 05000311/2016-002-00: Automatic Reactor Trip Due to Main Turbine Trip 
      a.  Inspection Scope 
On February 4, Salem Unit 2 automatically tripped from approximately 74 percent 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 AVR volts/hertz over excitation protection relay.  All emergency core cooling systems and emergency safeguards feature systems functioned as expected.  PSEG submitted this LER in accordance with 10 CFR 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)," specifically automatic actuation of the Reactor Protection System and the Auxiliary Feedwater System for this event.  The inspectors reviewed the LER, the associated cause evaluation, and interviewed PSEG
staff.  This LER is closed. 
      b.  Findings  Introduction.  A Green, self-revealing FIN was identified against MA-AA-716-010, "Maintenance Planning Process," Revision 18, when PSEG WOs did not specify the appropriate procedure to perform satisfactory modification testing of the main generator
AVR protective relay (model STV1).  Consequently, the relay actuated below its design
setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main turbine and reactor. 
41  Description.  On February 4, 2016, Unit 2 experienced an automatic main turbine and reactor trip from approximately 74 percent power, initiated by a trip of the main generator AVR STV 1 relay.  The STV1 is designed to protect the main generator, main power
transformers, and auxiliary transformer from over-excitation due to over-voltage operation, and consists of an adjustable pickup dial setting between 1.8 and
2.5 voltz/hertz (V/Hz), ranging from 108 - 150 V at 60 Hz.  PSEG design calculation
ES-7.007, "Salem Unit 2 Generator and Transformer Protective Relay Setpoint Determination," Revision 5, established a design setpoint for the STV1 relay of 138 V at 60 Hz, corresponding to a V/Hz dial setting of 2.3, with an associated time delay of
45 seconds.  Just prior to the Unit 2 trip on February 4, the main generator was
operating at approximately 26.1 kV following a manual MVAR adjustment, which corresponded to 2.175 V/Hz sensed at the STV1.  After the Unit 2 trip, PSEG troubleshooting determined the as-found pick-up value of the STV1 was 2.17 V/Hz.  The post-trip sequence-of-event data showed the STV1 time delay unit picked up 45 seconds
after exceeding 2.17 V/Hz, which tripped the AVR and resulted in a loss of field to the
main generator, thereby causing a turbine trip and coincident reactor trip.
In response to the Unit 2 reactor trip, PSEG performed RCE 70183932, "Unit 2 Automatic Reactor Trip on Generator Protection," to determine why the STV1 relay
actuated below the design setpoint.  PSEG identified two root causes:  1) setpoint drift
due to a damaged rheostat; and 2) the damaged rheostat was not identified due to an
inadequately planned work order that specified a less than adequate post-modification
test method.  PSEG DCP 80109718, "Salem Unit 2 AVR Replacement," supplement 10, documented that a "modification test" was required for the STV1 relay in accordance with Relay Department test procedures, which subsequently required the use of an
engineering-approved Relay Test Order (RTO).  However, Maintenance Planning
prepared WO 60122561-0014 to perform STV1 modification testing without specifying
the applicable test procedures.  MA-AA-716-010, step 4.5.7, states "If approved procedure(s) are available which cover all or part of the work scope, then specify in the work package to perform work in accordance with the procedure(s)."  Additionally, step
3.1.1 states, in part, "Maintenance Planners are responsible to interface with:  System
Engineers for providing supplemental technical direction on a case by case basis as needed;" and "Maintenance Shops to obtain information needed to produce an
adequately detailed work package."  Additionally, the RCE determined that WO 60122561-0014 directed the PSEG LTS department to perform modification testing of the STV1 relay.  However, LTS utilized
different testing procedures than the Relay department procedures specified in the DCP. 
The LTS modification testing performed on October 5, 2015, did not functionally test the STV1 relay at its design setpoint of 138 volts at 60 Hz, which corresponded to a dial setting of 2.3 as discussed above.  The RCE determined the manufacturer-specified
acceptance testing required verifying the V/Hz pick-up was within one percent of all V/Hz
adjustable dial settings, whereas the LTS procedure required the V/Hz pickup at a four
percent tolerance on the 2.0 dial setting, or four percent of 120 volts at 60 Hz.  The
STV1 relay pickup value from the LTS testing on October 5, 2015, fell outside of the one percent tolerance specified by the manufacturer, and LTS did not have a technical basis to support an allowable tolerance of four percent.  The RCE determined that returning
the relay to the manufacturer-specified setting of one percent would have required
adjusting the damaged rheostat to a position where the relay would not have functioned,
and therefore would have resulted in a failed acceptance test that would have prevented 
42  the relay from being installed in the plant.  The inspectors verified that the STV1 RTO specified a one percent tolerance at the design setpoint of 138 volts at 60 Hz. 
Analysis.  The inspectors determined that a performance deficiency existed because PSEG WOs did not specify the appropriate procedure to perform satisfactory modification testing of the main generator AVR protection relay STV1.  This issue was
more than minor since it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability (main generator and turbine trip) and challenge critical safety functions.  Specifically, due to a work order that was not planned properly, PSEG did not test the STV1 relay at the applicable design setpoint and manufacture-specified
tolerance.  Consequently, the relay actuated below its design setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main turbine and reactor.  Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this
finding was of very low safety significance, or Green, since mitigating equipment relied up to transition the plant to stable shutdown remained available.  The finding had a cross-cutting aspect in the area of Human Performance, Work Management, in that the organization implements a work process that includes the need for coordination with different groups or job activities.  Specifically, the PSEG process for planning the STV1 relay modification test WO included the need for maintenance
planners to coordinate with engineering to provide design setpoint and tolerance
specifications, as well as electrical maintenance departments to verify appropriate test procedures were specified in the WO.  The inspectors determined that PSEG did not adequately implement the work process in accordance with MA-AA-716-010. [H.5]
Enforcement.  MA-AA-716-010, Maintenance Planning Process, Revision 18, step 4.5.7, states "If approved procedure(s) are available which cover all or part of the work scope, then specify in the WO to perform work in accordance with the procedure(s)."  Contrary to the above, PSEG did not specify in the WO to perform work in accordance with
approved Relay department test procedures, and the associated RTO, for modification
testing of the STV1 relay on October 5, 2015.  Specifically, due to a work order that was
not planned properly, PSEG did not test the STV1 relay at the applicable design setpoint
and manufacturer-specified tolerance.  Consequently, the relay actuated below its design setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main turbine and reactor.  PSEG entered the issue in CAP as notification 20717849 and
performed RCE 70183932.  Planned corrective actions included replacing the failed
STV1 relay with a properly tested STV1 relay, verifying other STV relays were
appropriately tested as an extent of condition, and revising LTS department relay test procedures to ensure all applicable acceptance criteria are incorporated.  This finding does not involve enforcement action because no violation of a regulatory requirement
was identified.  Because this finding does not involve a violation and is of very low safety
significance, it is identified as a Finding.  (FIN 05000311/2016002-03, Inadequate Work Order Planning Results in Main Generator AVR STV Relay Trip)   
43  4OA5 Other Activities  .1 (Closed) URI 05000272; 311/2015008-01:  Inadequate Maintenance Rule System Performance Criteria (PC) Selection  a. Inspection Scope  In IR 05000272; 311/2015-008, inspectors identified a URI associated with inadequate Maintenance Rule Performance Criteria selection.
During this review the inspectors noted approximately 25 high safety significant systems
(HSS) with reliability PC greater than two maintenance preventable functional failures (MPFFs).  According to ER-AA-310-1003, Attachment 3, flowchart "Process for Selecting Reliability Performance Criteria," HSS SSCs, with reliability PC greater than or equal to
two MPFFs require SSC past performance documentation.  When the inspectors
requested that PSEG provide past performance documentation for the HSS SSCs with reliability PC greater than two MPFFs, PSEG provided documentation of HSS SSC PC approval from 1997, when the MRule Program was first implemented by PSEG.  The inspectors determined this documentation did not support the assigned PC, because it
did not consider the last 18 years of SSC past performance.
The inspectors also reviewed ER-AA-310-1007, "Maintenance Rule - Periodic (a)(3)
Assessment."  Step 5.11.1.4 states to determine that the number of MPFFs allowed per evaluation period is consistent with the assumptions in the probabilistic risk assessment (PRA).  Contrary to ER-AA-310-1007, step 5.11.4, the last two periodic (a)(3)
assessments performed by PSEG:  April 1, 2011, through September 9, 2012; and
October 1, 2012 through June 30, 2014; did not verify that the number of MPFFs allowed
per evaluation period were consistent with the assumptions in the PRA.  Additionally, ER-AA-310-1003, step 4.3.2, states, in part, that unless justified and approved by the Maintenance Rule Expert Panel, the number of MPFFs selected, as a Reliability PC,
may not be higher than the PRA-supplied number of functional failures.    The inspectors determined that the failure to meet ER-AA-310-1007, step 5.11.4, and
ER-AA-310-1003, step 4.3.2, was a performance deficiency.  However, at the time of inspection, as documented in the IR referenced above, the inspectors did not have the information needed to determine whether the performance deficiency was more than
minor.  The inspectors reviewed PSEG's actions in response to the URI, to determine whether the performance or condition of HSS SSCs was effectively controlled through
the performance of appropriate preventive maintenance under 10 CFR 50.65(a)(2), and also to determine if those HSS SSCs being monitored under 10 CFR 50.65(a)(1) were assigned appropriate goals and monitoring when considered against the appropriate
reliability PC threshold.  b. Findings  No findings were identified. 
PSEG captured the performance deficiency associated with the URI in the CAP under
notifications 20694641, 20699573, and 20716722.  In response, the PSEG Engineer performed detailed reviews of all the HSS reliability performance criteria against the basic event failure assumptions in the most recent PRA model.  For any systems that 
44  were identified to have reliability performance criteria deviations from the PRA basic event failure data, performance criteria changes were proposed to more closely align with the PRA.  Any proposed changes to system performance criteria were scheduled
for review by the Maintenance Rule Expert Panel, including a review of system
performance during the last 36 months.  The inspectors observed a sampling of the Expert Panel meetings, and reviewed meeting minutes for several others.  Upon
completion of the PSEG system reviews and expert panel meetings, a total of 12 HSS had reliability performance criteria reductions to more closely align with PRA failure data.  Five of the 12 systems were already being monitored under 10 CFR Part 50.65(a)(1)
prior to the reduction in performance criteria.  None of the 12 systems were moved to
(a)(1) as a result of the performance criteria reductions.  The inspectors sampled the
performance criteria adjustments to determine if HSS classified under (a)(2) were being appropriately monitored, and to verify that (a)(1) systems had appropriate goals assigned.  No performance deficiencies were identified.  The inspectors determined that
PSEG's scope of actions restored compliance with ER-AA-310-1007, step 5.11.4, and
ER-AA-310-1003, step 4.3.2.
This URI is closed. 
.2 License Renewal Commitments Inspection - Phase I Observation of License Renewal  Activities (71003 - 1 sample)  a. Inspection Scope  License renewal inspections verify the license conditions added as part of the renewed operating license, regulatory commitments, and selected aging management programs, and are implemented in accordance with 10 CFR Part 54, "Requirements for the Renewal of Operating Licenses for Nuclear Power Plants."  This inspection was completed during 1R24 to observe the implementation of select aging management program activities that are only available for observation during a refueling outage.  This inspection is described as "Phase 1" in NRC Inspection Manual Procedure 71003, Post-Approval Site Inspection for License Renewal and is intended to be completed during the last refueling outage prior to a nuclear power facility entering the period of extended operation.    As part of this review the inspectors observed the implementation of aging management programs and activities described in the license conditions, and regulatory commitments, as well as any testing or visual inspections of systems, structures, and components which are only accessible at reduced power levels or during a refueling outage.  The inspectors observed the ultrasonic thickness inspection of 1S-FWR-P-21-L1, which is a 6-inch diameter elbow in the Feedwater Recirculation system.  The component is part of the No. 12 SG Feed pump's 24-inch discharge header.  The inspectors observed the test grid being applied and the recording of measurements in accordance with test procedure OU-AA-335-004 under the flow accelerated program guidance ER-AA-430-1001 as directed by WO 30285966.  The inspectors also observed the preparation for the replacement of a Moisture Separator Reheat Drain system 4-inch diameter piping section.  The line is the drain from the No. 11 West Moisture Separator Reheat Main Steam Coil going to the No. 11 West Main Steam Coil Drain Tank.  This was the planned replacement of 27' feet of 
45  piping with corrosion resistant P22/Chrome Moly material.  The work was being performed on the 140' Turbine deck, under WO 60123316.  The inspectors observed the No. 12C Miscellaneous Drains drain manifold replacement spool piece.  This 12-inch diameter manifold receives three drain lines from the No. 15A, B, & C Bleed Steam lines and  is being replaced with corrosion resistant P22 (Chrome Moly) material.  The replacement was in progress and performed under WO 60123347.  After reviewing WO 60120251, the inspectors observed the removal and evaluation of random samples of inaccessible Salem Unit 1 containment liner covered by insulation.  The inspectors observed the containment interior liner insulation being removed, unremediated containment liner sections, and containment liner sections that were cleaned, brushed, and prepared for panel installation.  The inspectors reviewed ultrasonic thickness data to verify whether the program was in conformance with American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,  Section XI.  b. Findings and Observations  No findings were identified. 
4OA6 Meetings, Including Exit  On July 28, 2016, the inspectors presented the inspection results to Mr. Robert DeNight, Salem Operations Director, and other members of the PSEG staff.  On August 11, 2016,
an additional exit meeting was conducted and the inspectors presented inspection
results specific to the baffle bolt issues in this report to Mr. Eric Carr, Acting Station Vice
President.  During the August 11, 2016 exit meeting, PSEG management stated they may contest NCV 05000311/2016002-02 (Section 1R15), in a written response within 30 days of the date of this inspection report, using the process described in the cover
letter.  Additionally, the inspectors verified that no proprietary information was retained
by the inspectors or documented in this report. 
4OA7 Licensee-Identified Violations              The following violation of very low safety significance (Green) was identified by PSEG and is a violation of NRC requirements which meets the criteria of the NRC Enforcement
Policy, for being dispositioned as an NCV.  TS LCO 3.3.2.1 requires the ESFAS instrumentation channels and interlocks shown in Table 3.3-3 shall be operable.  Table 3.3-3, Function 8, requires two channels of AFW automatic actuation logic to be operable in Modes 1, 2, and 3.  With the number of operable channels one less than the required number of channels, TS
LCO 3.3.2.1 requires the inoperable channel to be restored to operable status within
6 hours or, be in at least Hot Standby within the next 6 hours and in at least Hot
Shutdown within the following 6 hours.  Contrary to TS LCO 3.3.2.1, one less than the required number of channels of AFW automatic actuation logic were operable from April 20, 2015, until Unit 2 entered Mode 4 for a scheduled refueling outage on
October 23, 2015.  This was due to the 21 AFW pump loop time response being
greater than the allowed TS value because the isolation valve for the pressure 
46  override defeat pressure transmitter was in the closed position.  PSEG entered this issue into the CAP as NOTFs 20709417, 20716352, 20710947, and 20711796.  This performance deficiency was more than minor because it was associated with
the human performance attribute of the Mitigating System cornerstone, and
adversely affected the cornerstone objective of ensuring the reliability and capability
of systems that respond to initiating events to prevent undesirable consequences.  The inspectors evaluated this finding using IMC 0609, Appendix A, "The Significance Determination Process for Findings At-Power," Exhibit 2.  The inspectors determined
that the finding was of very low safety significance (Green) because the finding did
not represent an actual loss of function of at least a single train for greater than its
TS allowed outage time.  ATTACHMENT:  SUPPLEMENTARY INFORMATION
 
A-1  Attachment SUPPLEMENTARY INFORMATION  KEY POINTS OF CONTACT  Licensee Personnel J. Perry, Site Vice President
E. Carr, Acting Site Vice President J. Barkhamer, PSEG Engineer J. Bergeron, Superintendent of Instrumentation and Controls
T. Cachaza, Senior Regulatory Compliance Engineer
R. Cary, Environmental Coordinator
L. Clark, Instrument Supervisor  B. Daly, Nuclear Environmental Affairs, Sustainability  D. Denelsbeck, RP Support Supervisor
B. Down, PSEG Engineer
P. Essner, System Engineer
P. Fabian, Salem Steam Generator Engineer T. Giles, Salem ASME Section XI Program Owner F. Grenier, RP Supervisor, Dosimetry
M. Hassler, Salem Radiation Protection Manager 
B. Kerkorian, Salem Steam Generator Supervisor
D. Kolasinski, Senior Engineer
A. Kraus, Manager, Nuclear Environmental Affairs T. MacEwen, Principal Compliance Engineer J. Mallon, Compliance Director
S. Markos, Manager, Design Engineering
J. Marooney, MPR Engineering Consultant
P. Martitz, Technical Support Superintendent J. Melchionna, Engineering Services  R. Moore, System Engineering Branch Manager
D. Mora, Salem NDE Program Coordinator
G. Morrison, Mechanical Engineer
T. Mulholland, Shift Operations Manager
A. Ochoa, Senior Compliance Engineer B. Ohmert, System Engineer T. Oliveri, Salem Unit 1 and Unit 2, NDE Manager
J. O'Rourke, Regulatory Affairs
J. Owad, Design Engineering
M. Phillips, Regulatory Assurance M. Pyle, Chemistry Manager N. Ruvis, Westinghouse
B. Sebastian, Manager Fire Protection/Industrial Safety
J. Stairs, Manager Plant Engineering 
C. Wend, Radiation Protection Manager
D. Yilgic, Lead Engineer Quality Control Chemistry
 
A-2      LIST OF ITEMS OPENED, CLOSED AND DISCUSSED  Open 05000272/2016002-01  URI  Baffle-Former Bolts with Identified Anomalies (Section 1R08) Open and Closed 05000311/2016002-02  NCV  Failure to Follow Operability        Determination Procedure for Unit 2 Baffle-Former Bolts (Section 1R15) 
05000311/2016002-03 FIN Inadequate Work Order Planning Results in Main Generator AVR STV Relay Trip (Section 4OA3.3) Closed 05000272:311/2015-008-01  URI  Inadequate Maintenance Rule System 
      Performance Criteria Selection (Section 4OA5)  05000311/2016-001-00  LER  Auxiliary Feedwater Loop Response Time 
      Exceeded Technical Specifications (Section 4OA3.1) 
05000311/2016-002-00 LER Automatic Reactor Trip Due to Main Turbine Trip (Section 4OA3.3)   
A-3      LIST OF DOCUMENTS REVIEWED  * Indicates NRC-identified
Section 1R01:  Adverse Weather Protection  Procedures SC.OP-SO.500-0001, Trip-A-Unit Scheme Operation, Revision 10
OP-AA-108-107-1001, Electric System Emergency Operations and Electric Systems Operator  Interface, Revision 4
Notifications 20731655* 20731657* 20731658* 20731659* 20731662 20731729*
20731735*
Section 1R04: Equipment Alignment  Procedures SC.MD-ST.125-0003, Quarterly Inspection and Preventive Maintenance of Units 1, 2, & 3 125  Volt Station Batteries, Revision 30
S1.OP-ST.CAN-0007, Refueling Operations - Containment Closure, Revision 25
S2.OP-SO.SW-0005, Service Water System Operation, Revision 42
S2.OP-SO.ABV-0001, Auxiliary Building Ventilation System Operation, Revision 25 S2.OP-SO.SJ-00001, Preparation of the Safety Injection System for Operation, Revision 19 OP-SA-102-106, Salem Operations Master List of Timed Actions, Revision 0
OP-AA-108-103, Locked Equipment Program, Revision 4
Notifications 20702800 20707221 20724871 20729878* 20732182 20732551
20732785* 20732994* 20733091
Drawings 205337, Sheet 1, No. 2 Unit Auxiliary Building - Ventilation, Revision 43
205242, Sheet 1, No. 2 Unit Service Water Nuclear Area, Revision 81 205242, Sheet 2, No. 2 Unit Service Water Nuclear Area, Revision 76 
Maintenance Orders/Work Orders 50180453 50182431 60125981 60129782
Section 1R05:  Fire Protection  Procedures FP-SA-2542, Pre-Fire Plan Unit 2 Spent Fuel/Component Cooling Heat Exchanger and Pump Area, Revision 0 FP-SA-2552, Pre-Fire Plan Unit 2 Boric Acid Evaporator Unit & Chemistry Area, Revision 0 FP-SA-2651, Pre-Fire Plan Unit 2 Service Water Intake Structure, Revision 0 FP-SA-2555, Pre-Fire Plan Unit 2 Diesel Generator Area, Revision 0
FP-SA-2556, Pre-Fire Plan Unit 2 Inner Piping Penetration Area & Chiller, Revision 0
 
A-4      Notifications 20723743 20730150* 20732820* 20732836*  Section 1R07:  Heat Sink Performance    Notifications 20726947 20727041 20727041
Maintenance Orders/Work Orders 30255437  Section 1R08:  In-service Inspection  NDE Procedures Liquid Penetrant Examination Procedure, OU-AA-335-002, Revision 3 Nondestructive Examination Procedure, Manual Ultrasonic Examination of Vessel Nozzle Inner  Radius Regions, Procedure Number 54-ISI-132-011, 1/27/2011
Nondestructive Examination Procedure, Ultrasonic Examination of Austenitic Piping Welds, Procedure Number 54-ISI-836-014, 8/21/2013 Areva NP Inc., Nondestructive Examination Procedure, Multi-Frequency Eddy Current Examination of Tubing, Procedure Number 54-ISI-400-021, 6/12/2013  Notifications 20682192 20694861 20697140 20697577 20697669 20699820 
20699859 20699910 20704139 20707057 20707057 20707125 
20712181 20712774 20713572 20713573 20713849 20713849 20714082 20716581 20720745 20722494 20724667 20725857 20726340 20726743 
Maintenance Orders/Work Orders 60114705
60123261 60126260 
Evaluations 70178672 70178814 70178821 70179375 70183001 70185980
Self Assessments  Check-In Self-Assessment, Salem INPO PWR Materials Review, 7/30/2015  NDE Records Salem Unit 1, Liquid Penetrant Report No. PT-16-002, 11-RHRHEX Vessel Support, 4/15/16 (Summary No.205170) Salem Unit 1, Liquid Penetrant Report No. PT-16-001, Pipe Lugs 8-RH-2116-10PL-1 thru 4, 4/15/16 (Summary No. 263631) Salem Unit 1, Liquid Penetrant Report No. PT-16-004, Pipe to Penetration IA, Component 12 SJ-2152-36PS-4, 4/19/16 (Summary No. 263904) 
A-5      Salem Unit 1, Liquid Penetrant Report No. PT-16-003, Inlet Nozzle-to-Pump (11 Charging Pump), Component 6-CV-2111-14R1, 4/15/16 (Summary No. 220757) Salem Unit 1, Liquid Penetrant Report No. PT-16-005, PIPE TO VALVE (11CS48)
component ID: 8-CS-2114-60, 4/15/16 (Summary No. 356640)
Design Change Package  80092579, Salem Unit 1  Steam Generator Bowl Drain Repair, SG 11, 12, 13, and 14 (removal  of Alloy 600 and associated 82/182 weld material from each SG Channel Head (SGCH)  bowl drain plugs PSEG NUCLEAR VTD NUMBER: 900013(019), Title Stress Analysis of Tube-Tubesheet Weld AREVA RSG, 11/23/15; Calculation Summary Sheet, 7/25/2015. PSEG Nuclear Work Order 70172201; Areva Reanalysis of Salem Steam Generator tube-to- tubesheet joint as a friction joint and to provide a revised SG stress analysis to PSEG for record purposes  WO #60123261, including weld history sheet; Replace SISJ - !SJ248 & 2SJ249 PSEG NUCLEAR LLC VTD NUMBER: AREVA 902739 (001); Salem Unit 1 SG Condition Monitoring for 1R22 AND Final Operational Assessment for Cycles 23 & 24; 8/8/13
Drawings: 02-9124528D, Salem Unit 1 Steam Generator Channel Head Drain Modification, Revision 001 Drawings: 1512E32, Salem REPLACEMENT Steam Generator General Layout; Salem Unit 1 Steam Generator Channel Head Drain Modification, Revision 1 Drawing 02-9124526B, Revision 001, Steam Generator Channel Head Drain Plug
Document No.: 51-9207624-000, Salem Unit 1 SG Condition Monitoring for 1R22 and Final Operational Assessment for Cycles 23 & 24
Other Documents NRC Regulatory Issues Summary 2016-02, Design Basis Issues Related To Tube-To-
Tubesheet Joints in Pressurized-Water Reactor Steam Generators, March 23, 2016 
PSEG NUCLEAR LLC VTD Number: 9000(019); AREVA Stress Analysis of Tube-Tubesheet Weld-AREVA, Vendor Number 32-9235210-001 
Section 1R11:  Licensed Operator Requalification Program  Other Documents SG-1624, Risk Management, SGFP Trip, SGTR, dated 05/21/16
Section 1R12:  Maintenance Effectiveness  Procedures ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Revision 14
Notifications 20689987 20729117* 20730512* 20730513* 20731038* 20732228*
Drawings 265029, Circ Water Swgr Bldg. 125VDC DC Distribution System, Revision 5
 
A-6      Section 1R13:  Maintenance Risk Assessments and Emergent Work Control  Procedures OP-AA-108-116, Protected Equipment Program, Revision 12
Notifications 20723781 20724495 20725030* 20725036 20726192 20727564 20727565 20728242 20731749 20733122 
Maintenance Orders/Work Orders 60128649
Other Documents ACE 20723873, 11 CFCU Low Speed Breaker Back-Flashed  Section 1R15:  Operability Determinations and Functionality Assessments  Calculations, Analysis, Engineering Evaluations, and Specifications MPR Associates Letter "Salem Service Water Discharge Header - Disposition of Degraded Joints", (0108-0471-0007, Rev 1), 6/3/2016 MPR Associates Letter, Salem PCCP Bell-and-Spigot Joint Degradation-Supplemental Information to (MPR-2650 Revision 0), 10/26/05 MPR Associates Letter, Salem Service Water Discharge Header - Disposition of Degraded Joints (0108-0471-0007, Rev 0), 4/29/2016 MPR Calculation 0108-0333-JEM-01, Structural Evaluation of Service Water Piping Thinned Joints, Revision 0 PSEG VTD 326511-001, "Structural Evaluation of Service Water Piping Thinned Joints"
PSEG VTD 326511-002, "Service Water" PSEG VTD 326511-003, "Service Water WEKO Seal Structural Repair Relief Request RAI Response Technical Input" PSEG VTD 326511-004, "Request for Use of Mechanical Repair System in Degraded Service Water Pipe Joints - Input for Response to NRG Request for Additional Information dated
October 29, 2013" S-C-SW-MEE-1975, Salem Units 1 & 2 Concrete Service Water Pipe Joints - Acceptance Criteria, Revision 0 
Drawings, Wiring Diagrams, and Piping and Instrumentation Diagrams 205243, Sheet 1, Auxiliary Building Control Air, Revision 49
0108-0471-0007, Salem Service Water Discharge Header - Disposition of Degraded Joints, 4/29/2016 
Evaluations 70097092 70097514 70103845 70131286 70144770
Notifications 20724198 20726264 20727538 20727590 20726001
20726320 20727126 20727354 20727430 20727678
20729040 20730485* 20727242 20727261
 
A-7      Procedures CC-AA-309-101, Engineering Technical Evaluation, Revision 10 OP-AA-108-115, Operability Determinations & Functionality Assessments, Revision 4
LS-AA-120, Issue Identification and Screening Process, Revision 13
LS-AA-125, Corrective Action Program, Revision 21
NO-AA-10, Quality Assurance Topical Report (QATR), Revision 84
S1.OP-PT.CA-0001, Emergency Control Air Compressor Functional Test, Revision 18 S1.OP-LR.CA-0005, Leak Rate Test 1CA920, Revision 1 SC.OP-LB.DF-0001, Diesel Fuel Oil Testing Program, Revision 3
Maintenance Orders/Work Orders 30265178 50140453 50154389 50154555 50158970 50172136 60115402 
Miscellaneous Inspection Manual Chapter 0326, Operability Determinations & Functionality Assessments for Conditions Adverse to Quality or Safety, dated December 3, 2015 Event Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel Internals, dated May 3, 2016 70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure, Revision 0 70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure, Revision 1 OpEval 2016-015, Potentially Degraded Baffle-Former Bolts in Salem Unit 2, Revision 0 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0
80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1
S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0 S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1 80117136 SUP01, Map of Degraded Bolt Locations, Revision 0
Westinghouse LTR-RIDA-16-125, Rev. 2, Salem Unit 1 Baffle Bolting One Cycle Replacement Pattern Summary Letter, dated May 31, 2016 WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2, Revision 0 ML13093A382, Request for Relief from ASME Code Defect Removal for Service Water Buried Piping, 4/3/2013 ML13227A338, PSEG Response to Request for Additional Information- Relief Request SC-14R-133, Alternative Repair for Service Water System Piping, 8/15/13 ML14016A123, PSEG Response to Request for Additional Information (RAI 31 and RAI 32) - Relief Request SC-14R-1 33, Alternative Repair for Service Water System Piping, 1/8/14 ML14058A228, PSEG Response to Request for Additional Information (RA133 - RAI36)-Relief Request SC-14R-133, Alternative Repair for Service Water System Piping, 2/27/14 ML14085A482, PSEG Response to Request for Additional Information (RAJ 37) - Relief Request SC-14R-133, Alternative Repair for Service Water System Piping, 3/26/14 ML14097A029, Salem Nuclear Generating Station, Units 1 And 2- Safety Evaluation of Relief Request No. SC-14R-133 for the Alternative Repair for Service Water System Piping (TAC
NOS. MF1375 AND MF1376), 4/8/2014 
A-8      Modifications 80110461 
Other Documents ML13093A382, Request for Relief from ASME Code Defect Removal for Service Water Buried Piping, 4/3/2013 ML13227A338, PSEG Response to Request for Additional Information- Relief Request SC-14R-133, Alternative Repair for Service Water System Piping, 8/15/13 ML14016A123, PSEG Response to Request for Additional Information (RAI 31 and RAI 32) - Relief Request SC-14R-1 33, Alternative Repair for Service Water System Piping, 1/8/14 ML14058A228, PSEG Response to Request for Additional Information (RA133 - RAI36)-Relief Request SC-14R-133, Alternative Repair for Service Water System Piping, 2/27/14 ML14085A482, PSEG Response to Request for Additional Information (RAJ 37) - Relief Request SC-14R-133, Alternative Repair for Service Water System Piping, 3/26/14 ML14097A029, Salem Nuclear Generating Station, Units 1 And 2- Safety Evaluation of Relief
Request No. SC-14R-133 for the Alternative Repair for Service Water System Piping (TAC
NOS. MF1375 AND MF1376), 4/8/2014  Section 1R18:  Plant Modifications  Condition Reports 20733528 20733526 20726264 20735142
Other Documents  80117136, Design Change Package for Salem Unit 1 Baffle-to-Former Bolt Replacement, Revision 0 80117378, Item Equivalency Evaluation for Replacement Baffle Bolts, dated 6/2/2016
EVAL-16-19, Salem Unit 1 Baffle-Former Bolt Replacement 1R24, Revision 0 LTR-RIAM-16-39, Transmittal of Westinghouse Specification 70041 EB to PSEG, dated 5/4/2016 S2016-156, 50.59 Screening Form for DCP 80117136, Revision 0
WCAP-18144-P, Generic Replacement Type 316 Cold-Worked Baffle-Former Bolt Qualification for 4-Loop Downflow Plants, Revision 0  Procedures 54-ISI-364-00, Remote Underwater In-Vessel Visual Inspection of Reactor Pressure Vessels, Vessel Internals, and Components in Pressurized Water Reactors, dated August 22,
2000 54-ISI-372-005, Remote Underwater In-Vessel Visual Inspection of Baffle to Former Bolts and Baffle Edge Bolts, dated September 23, 2011 54-UT-108-001, Ultrasonic Inspection of Internal Hex Head Baffle Bolts, dated April 24, 2011
GBRA 104650, Work Instruction Bolt Removal, Revision D
GBRA 173122, Repair and Inspection Sequence Plan for Baffle-former Bolt Replacement at NPP Salem, Revision 00   
A-9      Miscellaneous 180-9257342-000, NDE Services Final Report, Salem Unit 1, 1R24 Baffle to Former Plate Bolt Inspection Report, dated June 2, 2016 51-9256526-000, Technical Justification for Internal Hex Head E Baffle to Former Bolts Volumetric Examination at Westinghouse 4-Loop Reactors, dated April 25, 2016 IVVI-101, 01RF Examination Summary Record, VT-3 of Upper Core and Support Plate, dated 5/9/2001 Inservice Inspection Results, Bolt ID 5-55-C, dated May 3, 2016 Inservice Inspection Results, Bolt ID 6-75-C, dated April 30, 2016
NDE Personnel Qualification and Certification, VT-1, 2, & 3, Employee 16657, dated March 7, 2016 NDE Personnel Qualification and Certification, VT-1, 2, & 3, Employee 114882, dated March 4. 2015 MRP-228, Materials Reliability Program: Inspection Standard for PWR Internals- 2012 Update, Revision 1 54-UT-108-001, Ultrasonic Inspection of Internal Hex Head Baffle Bolts, Revision 1
80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1 S2016-156, 50.59 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0 S2016-156, 50.59 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1 80117136 SUP01, Map of Degraded Bolt Locations, Revision 0 Westinghouse LTR-RIDA-16-125, Rev. 2, Salem Unit 1 Baffle Bolting One Cycle Replacement Pattern Summary Letter, dated May 31, 2016 Westinghouse LTR-RIDA-16-125, Rev. 3, Salem Unit 1 Baffle Bolting One Cycle Replacement Pattern Summary Letter, dated July 11, 2016 WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2, Revision 0 WCAP-18144-P, Generic Replacement Type 316 Cold-Worked Baffle-Former Bolt Qualification for 4-Loop Downflow Plants, Revision 0 VEN-16-041, Remote Visual Examination: Baffle-former Bolts (Core Side), dated July 27, 2016
Section 1R19:  Post-Maintenance Testing  Procedures SC.MD-PM.CBV-0002, CFCU Motor Heat Exchanger Internal Inspection, Revision 20
SC.MD-PM.SW-0012, Enecon Tubesheet Cladding System, Revision 13
SC.IC-TI.ZZ-0104, Configuration Control for NUS Model MTH801 Summators, Revision 32 S2.IC-CC.RCP-0058, 2FT-542 #24 Steam Generator Flow Protection Channel I, Revision 42 
Notifications 20273570 20670175 20672463 20723478 20723652 20723765
20724185 20724217 20725095 20725111 20726481 20727534
Maintenance Orders/Work Orders 30205173 60120462 60128697 60129161 
 
A-10      Evaluations 70171681  Section 1R20:  Refueling and Other Outage Activities  Procedures LS-AA-119-1003, Calculating Work Hours, Revision 7 MA-AA-716-008-1010, Reactor Services Project FME Plan, Revision 2 S1.OP-IO.ZZ-0006, Hot Standby to Cold Shutdown, Revision 37
S1.OP-TM.ZZ-0001, Reactor Coolant System Pressure - Temperature Curves, Revision 4 SC.OP-DL.ZZ-0001, Reactor Coolant System Heatup/Cooldown Log, Revision 9 SC.OP-DL.ZZ-00012, Pressurizer Heatup/Cooldown Log, Revision 5  Notifications 20723957 20725589* 20725843 20725856 20725917 20726061*
20726121 20726355 20727113 20727298 20727697 20729566
Other Documents 1R24 Shutdown Safety Evaluation and Approval, dated 03/25/16  Section 1R22:  Surveillance Testing  Procedures S2.OP-ST.RHR-0001, Inservice Testing - 21 Residual Heat Removal Pump, Revision 29
S2.RA-ST.RHR-0001, Inservice Testing 21 Residual Heat Removal Pump Acceptance Criteria, 
Revision 12
S1.OP-ST.SSP-0001, Manual Safety Injection - SSPS, Revision 32
Notifications 20725279* 20725282* 20725581 20725603 20725936 20726147 20726148 20726342 20728892* 20728962* 20728963*
Maintenance Orders/Work Orders 50182657  Other Documents Unit 1 Operator logs for April 17 and 18, 2016
Section 1EP6:  Drill Evaluation  Procedures NC.EP-EP.ZZ-0405, Emergency Termination - Redaction - Recovery, Revision 
S2.OP-AB.Fuel-0001, Fuel Handling Incident, Revision 5
S2.OP-AB.CW-0001, Circulating Water System Malfunction, Revision 36
S2.OP-AB.CVC-0001, Loss of Charging, Revision 9  Notifications 20733529
20733001 
A-11      Other Documents S16-01, Salem All Facilities Training Drill, 06/16/16  Section 2RS1:  Access Control to Radiologically Significant Areas  Procedures RP-AA-301, Radiological Air Sampling Program, Revision 6 RP-AA-460, Control for High and Very High Radiation Areas, Revision 17 RP-AA-463, High Radiation Area Key Control, Revision 4
RP-AA-401-1001, Special Instruction for Highly Radioactive In-core Components, Revision 0
RP-SA-103, Radiological Control of Reactor Cavity and Spent Fuel Pool Operations, Revision 1
RP-AA-210, Dosimetry Issue, Usage, and Control, Revision 13 RP-AA-401, Operational ALARA Planning and Control, Revision 13 
Other Documents Audits 
Locked High Radiation Key Inventory Logs  Radiation Protection Job Guides (7 through 14) Radiological Survey data (various) 
Radiation Protection Plant Radionuclide Evaluation
Corrective Action Documents (various Notifications)
Section 2RS2:  Occupational ALARA Planning and Controls  Procedures RP-AA-401, Operational ALARA Planning and Control, Revision 13
CY-AP-120-1030, Estimating RCS Crud Release for Refueling Outage, Revision 1
S1. CH-IO.ZZ-111(Z), Salem Unit 1 Shutdown Chemistry Plan, Revision 8  Other Documents Refueling Outage Radiological Performance Report
ALARA Plans (various)
Radiation Protection Job Guides (7 through 14)
ALARA Work In-process Reviews Outage Chemistry Control Plan  1R24 Hard Gamma Projection
Corrective Action Documents (various Notifications)
Section 2RS3:  In-plant Airborne Radioactivity Control and Mitigation  Procedures RP-SA-103, Radiological Control of Reactor Cavity and Spent Fuel Pool Operations, Revision 1 RP-AA-220, Annual Bioassay Review, Revision 9 RP-AA-301, Radiological Air Sampling Program, Revision 6 RP-AA-401, Operational ALARA Planning and Control, Revision 13
NF-AA-430, Failed Fuel Action Plan, Revision 8
 
A-12      Other Documents Radiological Source Term Data - 10 CFR 61 waste stream report Airborne Radioactivity Sampling Results (various) 
Corrective Action Documents (various Notifications)
Section 2RS4:  Occupational Dose Assessment  Procedures RP-AA-401, Operational ALARA Planning and Control, Revision 13  Other Documents Radiation Protection Job Guides (7 through 14) General Source Term Data (various)
Corrective Action Documents (various notifications)
Section 2RS5:  Radiation Monitoring Instrumentation  Procedures RP-AA-301, Radiological Air Sampling Program, Revision 6
RP-AA-504, Routine Operation of the Radiation Protection Gross Counting facility
Other Documents  Instrument Source Check and Operability data (various) Corrective Action Documents (various notifications)  Section 2RS7:  Radiological Environmental Monitoring Program  Procedures RP-AA-228, 10 CFR 50.75(g0 and 10 CFR 50.72.30(d) Documentation, Revision 3 EN-AA-170-500, Meteorological Monitoring System Calibration and Maintenance (Metrological Tower), Revision 1 EN-AA-170-1000, Radiological Environmental Monitoring Program (REMP) and Meteorological Program (MET) Implementation, Revision 1  EN-AA-1001, REMP Vendor Dosimetry and Laboratory QA Program
EN-AA-170-4000, Radiological Ground water Protection program Implementation, Revision 0
EN-AA-170-4160, Station RGPP Controlled sample Points, Revision 0
EN-AA-170-4200, Disposal of Water from Excavation projects, Revision 0 EN-AA0170-4300, Investigative Process for Evaluation of Anomalous Tritium Data from On-site Wells, Revision 1 CY-AA-170-400, Radiological Ground water protection program, Revision 4 
AD-LTS-10, Laboratory and Testing Service (LTS) Quality Assurance Program, Revision 4 
Instruction NASSV-1.2.2NS, Service of Low Volume Sampler, Revision 19
Instruction MLKSA-1.1.2, Collection of Raw Milk samples, Revision 12 Instruction VGTSA-1.1.7, Collection of Vegetable, Vegetation and Fodder Crops, Revision 8 Instruction 1.1.9, Collection of Potable Water Samples, Revision 3 
Instruction TLDSV-1.2.1, Installation of Area Monitoring Dosimeters in the Field, Revision 16
Instruction AQUACOLL-1.1.10, Collection of Aquatic samples, Revision 11
Instruction GMSA -1.1.11, Collection of Game samples, Revision 3 Instruction VEGECEN-0.3.2, Salem/Hope Creek Vegetable Garden Census, Revision 6 
A-13      Instruction NRESCEN, Salem/Hope Creek Nearest Resident Census, Revision 5 Instruction MLKCEN 0.3.1, Salem/Hope Creek Census of Milk Animals, Revision 6 Instruction H2OSA-1.1.1, Collection of Water Samples, Revision 13
Instruction SOLSA -1.1.3, Collection of Soil Samples, Revision 8
Instruction ESS-1.1.5, Collection of Sediment Samples, Revision 9
Instruction ESFCH -1.1.6, Pickup of Fish and Crab Samples, Revision 7
Other Documents  Salem and Hope Creek Offsite Dose Calculation Manuals (ODCM) UFSAR Section 11.6, Offsite Radiological Monitoring Program
Hope Creek Nuclear Station Buried and Underground Piping Asset Management Plan,  Revision 0 Salem and Hope Creek 2015 Annual Effluent Releases Reports NEI-07-07, Structure, System, Component (SCC) Review for Turbine Roof Structure (Hope Creek) Salem and Hope Creek Annual Radiological Environmental Monitoring Reports
Salem/Hope Creek Meteorological Program Status Report (2014, 2015)  Salem/Hope Creek Metrological Tower Updated Vegetation Review, June 3, 2016 Comparison of 2015 Atmospheric Dispersion Factors for Salem and Hope Creek, dated March 28, 2016 Chemistry, Radwaste, Effluent and Environmental Monitoring Audit Report, NOSA-SLM-16-04, May 11, 2016 2016 Self-Assessment REMP Program Inspection Teledyne Brown Environmental Service Annual Quality Assurance Report  GEL 2015 - Annual Quality Assurance Report (REMP)
Residential Survey, dated December 22, 2015
Milk Animal Survey dated December 2015
Vegetable garden Survey dated August 2015 Calibration Data (Dry Gas Meters 61182898, 14522708, 2424590) Calibration Data (Laminar Flow Element 16300942) 
Global Solutions Annual Testing, dated May 26, 2015
Passive Environmental Dosimetry Calibration data
Ground Water Monitoring Data and RGPP Data
Salem/Hope Creek Part 61 Analysis Review, dated April 27, 2016  Salem Remedial Action Plan Progress Reports Corrective Action Documents (various Notifications)
Ground Water Monitoring Data
Corrective Action Documents (various Notifications)
Section 4OA2:  Problem Identification and Resolution  Condition Reports 20724198 20726264 20727538 20727590 20728329 20732892
20731786 20725142 20736630
Maintenance Orders/Work Orders 70136205 70140618 70154315 70168067 70168874 70180750 70182469 70182519 70183590 70183629
 
A-14      Miscellaneous Westinghouse LTR-RIDA-16-125, Rev. 2, Salem Unit 1 Baffle Bolting One Cycle Replacement Pattern Summary Letter, dated May 31, 2016 Westinghouse LTR-RIDA-16-125, Rev. 3, Salem Unit 1 Baffle Bolting One Cycle Replacement Pattern Summary Letter, dated July 11, 2016 WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2, Revision 0 Non-Proprietary Safety Evaluation of WCAP-17096-NP, Revision 2, Reactor Internals Acceptance Criteria Methodology and Data Requirements (TAC No. ME4200). (ADAMS
Accession No. ML16061A243), dated May 3, 2016 Westinghouse Calculation Note, CN-RIDA-15-34, Rev. 4, "Units 1 and 2 Acceptable Baffle-Former LOCA and Seismic Analysis, dated May 16, 2016 Westinghouse Calculation Note CN-RIDA-15-64, Rev. 2, Salem Units 1 and 2 Acceptable Baffle-Former Bolting Pattern Fuel Grid Impact Analysis, dated May 16, 2016 Event Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel Internals, dated May 3, 2016 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1 S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0 S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1 80117136 SUP01, Map of Degraded Bolt Locations, Revision 0 Westinghouse LTR-RIDA-16-112, Rev. 0, Summary of Salem Unit 1 Baffle-Former Bolt Real-time Analysis Results, dated May 11, 2016 WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2, Revision 0 Westinghouse LTR-RIAM-16-38 Rev. 0, Salem Unit 1 Real-Time Analysis Results for LOCA/Seismic Dynamic Analysis and Fuel Grid Impact Analysis, dated May 3, 2016 Westinghouse LTR-RIAM-16-39 Rev. 0, Transmittal of Westinghouse Specification 70041 EB to Public Service Enterprise Group, dated May 4, 2016 Information Notice 98-11, Cracking of Reactor Vessel Internal Baffle-former Bolts in Foreign Plants, dated March 24, 1998 Eval-16-19, Westinghouse Electric Company 10 CFR 50.59 Applicability Determination, Salem Unit 1 Baffle-former Bole Replacement 1R24, Revision 0 MRP-228, Materials Reliability Program: Inspection Standard for PWR Internals - 2012 Update, Revision 1 Unit 1 and 2 Technical Specifications, Revision 28 
ACM 16-011, Baffle Plates Monitoring, dated June 17, 2016 ACM 16-011, Baffle Plates Monitoring, dated July 25, 2016 WCAP-15030-NP-A, Westinghouse Methodology for Evaluating the Acceptability of Baffle- Former-Barrel Bolting Distributions Under Faulted Load Conditions, dated January 1999 NRC Safety Evaluation of Topical Report wCAP-25029, Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions Under Faulted
Load Conditions (TAC No. MA1152), dated November 16, 1998 NRC Letter, Leak Before Break Evaluation of Primary Loop Piping, Salem Nuclear Generating Station, Units 1 and 2 (TAC NOS.  M85799 and M85800), dated May 25, 1994 51-92566526, Technical Justification for Internal Hex Head E Baffle to Former Bolts Volumetric Examination at Westinghouse 4-Loop Reactors, dated April 28 2016 
A-15      54-ISI-364-00, IVVI Inspection Data Sheet Salem 1R14, dated May 8, 2001 Areva Letter, Completion and Status of Octants 1, 2, 3, 4, 5, 6, 7, and 8 (i.e., 1-8), dated May 5, 2016 OTDM 16-005, Salem Unit 2 Baffle to Former Bolting of Reactor Vessel Internals, dated June 16, 2016 WCAP-18144-P, Generic Replacement Type 316 Cold-Worked Baffle-Former Bolt Qualification for 4-Loop Downflow Plants, Revision 0 Westinghouse LTR-LIS-11-381, LOCA Assessment of Core Coolable Geometry for Grid Deformation in Peripheral Fuel Assemblies, dated June 27, 2011 Event Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel Internals, dated May 3, 2016 70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure, Revision 0 70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure, Revision 0 Op Eval 2016-015, Potentially Degraded Baffle-Former Bolts in Salem Unit 2, Revision 0
VEN-16-041, Remote Visual Examination Baffle-former Bolts (Core Side), dated July 27, 2016  Procedures ER-AA-2003, System Performance Monitoring and Analysis, Revision 10
54-ISI-364-00, Remote Underwater In-Vessel Visual Inspection of Reactor Pressure Vessels, Vessel Internals, and Components in Pressurized Water Reactors, dated August 22,
2000 54-UT-108-001, Ultrasonic Inspection of Internal Hex Head Baffle Bolts, dated April 28, 2016 
Notifications 20704666 20706027 20709417 20710340* 20710947 20711723
20711796 20715617 20716352 20716358 20716401 20716402 20716404 20716754 20721375 20726684 20728492* 20730946 20734279* 20734280* 20734281* 20734284* 20734286* 20734856*
Other Documents S2.OP-ST.SSP-0011(Q), Engineered Safety Features Response Time Testing performed October 18, 2015 NRC Event Notification 51663 Exelon PowerLabs Report PSE-65422, 07/01/13
Exelon PowerLabs Report PSE-82817, 11/13/13
Exelon PowerLabs Report PSE-00915, 03/18/14
Exelon PowerLabs Report PSE-19717, 10/22/15 Exelon PowerLabs Report PSE-88030, Draft  Section 4OA3:  Follow-up of Events and Notices of Enforcement Discretion  Notifications 20733919*   
A-16      LIST OF ACRONYMS  10 CFR  Title 10 of the Code of Federal Regulations AC  alternating current
ACE  apparent cause evaluation 
ADAMS  Agencywide Documents Access and Management System AFW  auxiliary feedwater ALARA  as low as is reasonably achievable ASME  American Society of Mechanical Engineers
AVR  automatic voltage regulator
CAP  Corrective Action Program
CCE  common cause evaluation CFCU  containment fan cooling unit  CFR  Code of Federal Regulations CS  containment spray
DC  direct current
DCP  design change package EC  eddy current ECAC  emergency compressed air compressor
ECCS  Emergency Core Cooling System
ECT  eddy current testing
EDG  emergency diesel generator
EFPY  effective full power years EPD  electronic personal dosimeter EPRI  Electric Power Research Institute
ESFAS  engineered safety feature actuation system
FIN  finding
FOSAR  foreign object search and retrieval  GPI  Groundwater Protection Initiative HRA  high radiation area
HSS  high safety significant systems
HX  heat exchanger
IMC  Inspection Manual Chapter
IOD  immediate operability determination IR  inspection report ISI  In-service inspection
IASCC  Irradiation Assisted Stress Corrosion Cracking
kV    kilovolt
LCO  limiting conditions for operation LER  licensee event report LHRA  locked high radiation area
LLRT  local leak rate test 
LTS  Laboratory and Testing Services
MPFF  maintenance preventable functional failure(s)
MR  maintenance rule MRC  Management Review Committee NCV  non-cited violation
NDE  nondestructive examination
NEI  Nuclear Energy Institute 
A-17      NOS  Nuclear Oversight NOTF  notification(s) NRC  Nuclear Regulatory Commission
NVLAP  National Voluntary Laboratory Accreditation Program
ODCM  Offsite Dose Calculation Manual
PC  performance criteria
PI  performance indicator(s) PM  preventive maintenance PRA  probabilistic risk assessment 
PSEG  Public Service Enterprise Group Nuclear LLC
QHPI  Quick Human Performance Investigation 
RCE  root cause evaluation RCS  reactor coolant system REMP  Radiological Environmental Monitoring Program
RFO  refueling outage
RG  regulatory guide
RHR  residual heat removal RP  radiation protection RTO  relay test order
RWP  radiation work permit(s)
SBO  station blackout
SDP  significance determination process
SF  spent fuel SG  steam generator SI  safety injection 
SOC  Station Oversight Committee
SSC  structure, system, and component 
SW  service water TS  technical specification(s) UFSAR    Updated Final Safety Analysis Report 
URI  unresolved item
UT  ultrasonically testing
V/Hz  volt/hertz
VHRA  very high radiation areas WGE  work group evaluation WOs    work order(s)
 


P. Sena                                            -2-
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs
Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be
available electronically for public inspection in the NRCs Public Document Room or from
the Publicly Available Records component of the NRCs Agencywide Documents Access and
Management System (ADAMS). ADAMS is accessible from the NRC website at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
                                                Sincerely,
                                                /RA/
                                                Fred L. Bower, III, Chief
                                                Reactor Projects Branch 3
                                                Division of Reactor Projects
Docket Nos. 50-272 and 50-311
License Nos. DPR-70 and DPR-75
Enclosure:
Inspection Report 05000272/2016002 and
  05000311/2016002
  w/Attachment: Supplementary Information
cc w/encl: Distribution via ListServ
ML16266A224
                                            Non-Sensitive                                Publicly Available
      SUNSI Review
                                          Sensitive                                    Non-Publicly Available
OFFICE    RI/DRP                  RI/DRP                    RI/DRS                RI/DRP          RI/DRP
NAME      PFinney/RB              RBarkley                  MGray                MScott          FBower
DATE      9/16/16                  9/14/16                  9/16/16              9/22/16        9/22/16
                                       
                                      1
              U.S. NUCLEAR REGULATORY COMMISSION
                                  REGION I
Docket Nos.  50-272 and 50-311
License Nos. DPR-70 and DPR-75
Report Nos.  05000272/2016002 and 05000311/2016002
Licensee:    PSEG Nuclear LLC (PSEG)
Facility:    Salem Nuclear Generating Station, Units 1 and 2
Location:    P.O. Box 236
            Hancocks Bridge, NJ 08038
Dates:      April 1, 2016 through June 30, 2016
Inspectors:  P. Finney, Senior Resident Inspector
            A. Ziedonis, Resident Inspector
            E. Burket, Emergency Preparedness Specialist
            G. DiPaolo, Senior Reactor Inspector
            M. Draxton, Project Engineer
            J. Kulp, Senior Reactor Inspector
            M. Modes, Senior Reactor Inspector
            R. Nimitz, Senior Health Physicist
            T. OHara, Reactor Engineer
            D. Orr, Senior Reactor Inspector
            R. Vadella, Project Engineer
            J. Poehler, Senior Materials Engineer
Approved By: Fred L. Bower, III, Chief
            Reactor Projects Branch 3
            Division of Reactor Projects
                                                            Enclosure
                                                            2
                                          TABLE OF CONTENTS
REPORT DETAILS ....................................................................................................................... 5
1.  REACTOR SAFETY .............................................................................................................. 5
  1R01  Adverse Weather Protection ...................................................................................... 5
  1R04  Equipment Alignment .................................................................................................. 7
  1R05  Fire Protection ............................................................................................................. 7
  1R07  Heat Sink Performance .............................................................................................. 7
  1R08  In-service Inspection Activities ................................................................................... 7
  1R11  Licensed Operator Requalification Program ............................................................ 12
  1R12  Maintenance Effectiveness ...................................................................................... 12
  1R13  Maintenance Risk Assessments and Emergent Work Control ................................ 13
  1R15  Operability Determinations and Functionality Assessments .................................... 14
  1R18  Plant Modifications ................................................................................................... 19
  1R19  Post-Maintenance Testing ....................................................................................... 20
  1R20  Refueling and Other Outage Activities ...................................................................... 20
  1R22  Surveillance Testing ................................................................................................. 21
  1EP6  Drill Evaluation ........................................................................................................ 22
2.  RADIATION SAFETY .......................................................................................................... 22
  2RS1  Radiological Hazard Assessment and Exposure Controls ....................................... 22
  2RS2  Occupational ALARA Planning and Controls ........................................................... 24
  2RS3  In-Plant Airborne Radioactivity Control and Mitigation ............................................. 25
  2RS4  Occupational Dose Assessment .............................................................................. 26
  2RS5  Radiation Monitoring Instrumentation ...................................................................... 27
  2RS7  Radiological Environmental Monitoring Program (REMP) ....................................... 28
4.  OTHER ACTIVITIES............................................................................................................ 29
  4OA1  Performance Indicator Verification ............................................................................ 29
  4OA2  Problem Identification and Resolution ..................................................................... 29
  4OA3  Follow-Up of Events and Notices of Enforcement Discretion.................................... 39
  4OA5  Other Activities .......................................................................................................... 43
  4OA6  Management Meetings ............................................................................................. 45
  4OA7  Licensee-identified Violations ................................................................................... 45
ATTACHMENT: SUPPLEMENTARY INFORMATION ............................................................... 46
SUPPLEMENTARY INFORMATION ........................................................................................ A-1
KEY POINTS OF CONTACT .................................................................................................... A-1
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED ......................................................... A-2
LIST OF DOCUMENTS REVIEWED ........................................................................................ A-3
LIST OF ACRONYMS............................................................................................................. A-16
                                                    3
                                                SUMMARY
Inspection Report (IR) 05000272/2016002, 05000311/2016002; 04/01/2016 - 06/30/2016;
Salem Nuclear Generating Station Units 1 and 2; Operability Determinations and Functionality
Assessments; Follow-Up of Events and Notices of Enforcement Discretion.
This report covered a three-month period of inspection by resident inspectors and announced
inspections performed by regional inspectors. The inspectors documented one self-revealing
finding of very low safety significance (Green), one non-cited violation (NCV), one finding (FIN)
and one licensee identified violation. The significance of most findings is indicated by their color
(i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection
Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated April 29, 2015.
Cross-cutting aspects are determined using IMC 0310, Aspects Within Cross-Cutting Areas,
dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance
with the NRCs Enforcement Policy, dated February 4, 2015. The NRCs program for
overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.
Cornerstone: Mitigating Systems and Initiating Events
    Green. The inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code
    of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, "Instructions, Procedures,
    and Drawings," because, from June 15, 2016 until July 26, 2016, PSEG did not accomplish
    actions necessary to provide adequate confidence that a structure, system, and component
    (SSC) would perform satisfactorily in service (an activity affecting quality) as prescribed by a
    documented procedure. Specifically, although PSEG had concluded Salem Unit 2 is
    susceptible to baffle bolt failure due to its design and operating life (but less susceptible than
    Salem Unit 1), PSEG inadequately implemented Procedure OP-AA-108-115, "Operability
    Determinations & Functionality Assessments," Sections 4.7.14 followed by Sections
    4.7.18-4.7.20 to perform an operability evaluation (OpEval) to justify continued operation of
    the unit until the next refueling outage. PSEGs immediate corrective actions included
    entering the issue into its corrective action program (NOTF 20736630) and documenting an
    operability evaluation to support the basis for functionality of the baffle structure and the
    operability of the emergency core cooling system (ECCS) and reactivity control systems.
    This finding is more than minor because it is associated with the equipment performance
    attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to
    ensure the availability, reliability, and capability of systems that respond to initiating events to
    prevent undesirable consequences, in that degradation of a significant number of baffle bolts
    could result in baffle plates dislodging following an accident. This issue was dispositioned as
    more than minor because it was also similar to example 3.j of IMC 0612, Appendix E,
    Examples of Minor Issues, in that the condition resulted in reasonable doubt of operability
    of the ECCS and additional analysis was necessary to verify operability. In accordance with
    IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A,
    The Significance Determination Process for Findings At-Power, issued June 19, 2012, the
    inspectors screened the finding for safety significance and determined it to be of very low
    safety significance (Green), since the finding did not represent an actual loss of system or
    function. After inspector questioning, PSEG performed OpEval 2016-015, which provided
    sufficient bases to conclude the Unit 2 baffle assembly would support ECCS and control rod
    system operability until the next refueling outage. This finding is related to the cross-cutting
                                                  4
  aspect of Operating Experience because PSEG did not effectively evaluate relevant internal
  and external operating experience. Specifically, PSEG did not adequately evaluate the
  impact of degraded baffle bolts in Unit 2 when directly relevant operating experience was
  identified at Unit 1. [P.5] (Section 1R15)
  Green. A Green, self-revealing finding (FIN) was identified against MA-AA-716-010,
    Maintenance Planning Process, Revision 18, when PSEG work orders (WOs) did not
    specify the appropriate procedure to perform satisfactory modification testing of the main
    generator automatic voltage regulator (AVR) protective relay (model STV1). Consequently,
    the relay actuated below its design setpoint on February 4, 2016, resulting in an automatic
    trip of the Unit 2 main turbine and reactor. PSEG entered the issue in their Corrective
    Action Program (CAP) and performed a root cause evaluation (RCE), replaced the failed
    STV1 relay with a properly tested relay, verified other STV relays were appropriately tested
    as an extent of condition, and initiated an action to revise Laboratory Testing Services (LTS)
    department relay test procedures to ensure all applicable acceptance criteria will be
    incorporated.
    The inspectors determined that a performance deficiency existed because PSEG WOs did
    not specify the appropriate procedure to perform satisfactory modification testing of the main
    generator AVR protection relay. This issue was more than minor since it was associated
    with the procedure quality attribute of the Initiating Events cornerstone and adversely
    impacted its objective to limit the likelihood of events that upset plant stability (turbine and
    reactor trip) and challenge critical safety functions. Using IMC 0609, Attachment 4 and
    Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety
    significance, or Green, since mitigating equipment relied up to transition the plant to stable
    shutdown remained available. The finding had a cross-cutting aspect in the area of Human
    Performance, Work Management, in that the PSEG did not adequately implement the work
    process to coordinate with engineering and maintenance departments as needed to
    appropriately plan the STV1 relay modification test WO. [H.5] (Section 4OA3.3)
Other Findings
A violation of very low safety significance that was identified by PSEG was reviewed by the
inspectors. Corrective actions taken or planned by PSEG have been entered into PSEGs CAP.
This violation and corrective actions tracking number are listed in Section 4OA7 of this report.
                                                    5
                                          REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at 100 percent power. The unit was shut down for a
refueling outage on April 14.
Unit 2 began the inspection period at 100 percent power. The unit remained at or near
100 percent power until June 28, when the unit tripped due to actuation of the main generator
protection system. The unit remained shut down at the end of the inspection period.
1.      REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01 - 1 sample)
.1      Summer Readiness of Offsite and Alternate Alternating Current Power Systems
    a. Inspection Scope
        The inspectors reviewed plant features and procedures for the operation and continued
        availability of the offsite and alternate alternating current (AC) power system to evaluate
        readiness of the systems prior to seasonal high grid loading on May 31. The inspectors
        reviewed PSEGs procedures affecting these areas and the communications protocols
        between the transmission system operator and PSEG. This review focused on changes
        to the established program and material condition of the offsite and alternate AC power
        equipment. The inspectors assessed whether PSEG established and implemented
        appropriate procedures and protocols to monitor and maintain availability and reliability
        of both the offsite AC power system and the onsite alternate AC power system. The
        inspectors evaluated the material condition of the associated equipment by interviewing
        the responsible system manager, reviewing condition reports and open WOs, and
        walking down portions of the offsite and AC power systems including the 500 kilovolt
        (kV).
    b. Findings
        No findings were identified.
1R04 Equipment Alignment
.1      Partial System Walkdown (71111.04Q - 4 samples)
    a. Inspection Scope
        The inspectors performed partial walkdowns of the following systems:
          Unit 1, 1A and 1C 125V direct current (DC) system during 1B 125V DC battery
            inoperability on April 6
          Unit 1, Containment penetrations during irradiated fuel moves on April 19
                                                6
        Unit 2, Service water (SW) system during 21 SW pump emergent repairs on June 7
        Unit 2, Auxiliary building ventilation with damper 2ABV2 failed open on June 16
      The inspectors selected these systems based on their risk-significance relative to the
      reactor safety cornerstones at the time they were inspected. The inspectors reviewed
      applicable operating procedures, system diagrams, the Updated Final Safety Analysis
      Report (UFSAR), technical specification(s) (TSs), WOs, notifications (NOTFs), and the
      impact of ongoing work activities on redundant trains of equipment in order to identify
      conditions that could have impacted the systems performance of its intended safety
      functions. The inspectors also performed field walkdowns of accessible portions of the
      systems to verify system components and support equipment were aligned correctly and
      were operable. The inspectors examined the material condition of the components and
      observed operating parameters of equipment to verify that there were no deficiencies.
      The inspectors also reviewed whether PSEG staff had properly identified equipment
      issues and entered them into the CAP for resolution with the appropriate significance
      characterization.
  b. Findings
      No findings were identified.
.2    Full System Walkdown (71111.04S - 1 sample)
  a. Inspection Scope
      On June 22, 2016, the inspectors performed a complete system walkdown of accessible
      portions of the Unit 2 safety injection (SI) to verify the existing equipment lineup was
      correct. The inspectors reviewed operating procedures, surveillance tests, drawings,
      equipment line-up check-off lists, and the UFSAR to verify the system was aligned to
      perform its required safety functions. The inspectors also reviewed electrical power
      availability, component lubrication and equipment cooling, hanger and support
      functionality, and operability of support systems. The inspectors performed field
      walkdowns of accessible portions of the systems to verify as-built system configuration
      matched plant documentation, and that system components and support equipment
      remained operable. The inspectors confirmed that systems and components were
      aligned correctly, free from interference from temporary services or isolation boundaries,
      environmentally qualified, and protected from external threats. The inspectors also
      examined the material condition of the components for degradation and observed
      operating parameters of equipment to verify that there were no deficiencies.
      Additionally, the inspectors reviewed a sample of related notifications and WOs to
      ensure PSEG appropriately evaluated and resolved any deficiencies.
  b. Findings
      No findings were identified.
                                                  7
1R05 Fire Protection
.1      Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)
    a. Inspection Scope
        The inspectors conducted tours of the areas listed below to assess the material
        condition and operational status of fire protection features. The inspectors verified that
        PSEG controlled combustible materials and ignition sources in accordance with
        administrative procedures. The inspectors verified that fire protection and suppression
        equipment was available for use as specified in the area pre-fire plan, and passive fire
        barriers were maintained in good material condition. The inspectors also verified that
        station personnel implemented compensatory measures for out of service, degraded, or
        inoperable fire protection equipment, as applicable, in accordance with procedures.
          Unit 2, Spent fuel (SF) and component cooling heat exchangers (HXs) on May 12
          Unit 2, Boric acid evaporator unit and chemistry area on May 20
          Unit 2, SW pump bays during 21 SW pump maintenance on June 8
          Unit 2, 2B and 2C emergency diesel generator (EDG) rooms on June 16
          Unit 2, Chiller room while protected on June 16
    b. Findings
        No findings were identified.
1R07 Heat Sink Performance (711111.07A - 1 sample)
    a. Inspection Scope
        The inspectors reviewed the 12 SI pump lube oil cooler readiness and availability to
        perform its safety functions. The inspectors reviewed the design basis for the
        component and verified PSEGs commitments to NRC Generic Letter 89-13, Service
        Water Requirements Affecting Safety-Related Equipment. The inspectors performed
        inspection of the as-found conditions, and discussed the results of previous inspections
        with PSEG staff. The inspectors verified that PSEG initiated appropriate corrective
        actions for identified deficiencies. The inspectors also verified that the number of tubes
        plugged within the HX did not exceed the maximum amount allowed.
    b. Findings
        No findings were identified.
1R08 In-service Inspection Activities (71111.08 - 1 sample)
  a.    Inspection Scope
        Inspectors from the NRC Region I Office, specializing in materials and in-service
        examination activities, observed portions of PSEGs activities involving baffle bolt
        examinations and replacements during the Salem Unit 1 spring 2016 refueling outage
        (1R24). PSEG notified the NRC of problems with baffle bolts in Event
                                            8
Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel
Internals. During May 17-19, 2016, and June 20-23, 2016, inspectors conducted an
inspection of PSEGs evaluation of the baffle bolt ultrasonic testing results and visual
examination performed during 1R24. The inspectors reviewed documentation,
interviewed personnel, and reviewed video recordings of visual examinations performed
during the current and previous refueling outages. The inspectors also observed in-
progress baffle bolt replacement activities.
Nondestructive Examination and Welding Activities (Section 02.01)
The inspectors conducted a review of PSEGs implementation of in-service inspection
(ISI) program activities for monitoring degradation of the reactor coolant system
boundary, risk significant piping and components, and containment systems during
Salem Unit 1 refueling outage 1R24. The sample selection was based on the inspection
procedure objectives and risk priority of those pressure retaining components in these
systems where degradation would result in a significant increase in risk. The inspectors
observed in-process nondestructive examination (NDE), reviewed records, and
interviewed personnel to verify the following: a) that non-destructive activities were
performed in accordance with American Society of Mechanical Engineers (ASME) Boiler
and Pressure Vessel Code Section XI, 2004 Edition, no Addenda, requirements; b) that
indications and defects, if present, were dispositioned in accordance with the ASME
Code or an NRC approved alternative; and, c) that relevant indications were compared
to previous examinations to determine if any changes occurred.
The inspectors reviewed the ultrasonic testing (UT) procedure used for the examination
of the Unit 1 baffle bolts to verify it met the requirements of the ASME Boiler and
Pressure Vessel Code and the applicable guidance in the Electric Power Research
Institutes Materials Reliability Program (MRP-227 and 228). The inspectors reviewed
the UT data records for the examinations performed during the 1R24 refueling outage to
verify that activities were performed in accordance with applicable examination
procedures.
The inspectors reviewed video from the visual examination of the baffle bolts performed
in the current refueling outage (RFO). The inspectors also reviewed video of visual
examinations performed during Unit 1 RFOs in 2001, 2013, and 2014 to assess the
as-found conditions of the baffle bolts. The inspectors reviewed certifications of the NDE
technicians performing the examinations to verify the examinations were performed by
qualified individuals in accordance with approved procedures and the results reviewed
and evaluated by certified Level III NDE personnel.
The inspectors performed a sample of observations of NDE activities and reviewed
records of NDE activities. The review sample consisted of two or three types of NDE
activities, including at least one volumetric examination.
ASME Code Required Examinations
Salem Unit 1, Liquid Penetrant Report No. PT-16-002, 11-RHRHEX Vessel Support,
        4/15/16, (Summary No.205170) [record review]
Salem Unit 1, Liquid Penetrant Report No. PT-16-001, Pipe Lugs 8-RH-2116-10PL-1
        through 4, 4/15/16, (Summary No. 263631) [record review]
                                        9
Salem Unit 1, Liquid Penetrant Report No. PT-16-004, Pipe to Penetration IA,
        Component 12 SJ-2152-36PS-4, 4/19/16, (Summary No. 263904) [record review]
Salem Unit 1, Liquid Penetrant Report No. PT-16-003, Inlet Nozzle To 11
        Charging Pump, Component 6-CV-2111-14R1, 4/15/16,
        (Summary No. 220757) [record review]
Salem Unit 1, Liquid Penetrant Report No. PT-16-005, Pipe-to-Valve (11CS48)
        [record review] Component ID: 8-CS-2114-60, 4/15/16, (Summary No. 56640)
Salem Unit 1, Ultrasonic examination (Summary #006325) Report UT-16-039,
        Component ID: 1-PZR-20, Pressurizer, shell J weld [Observed]
Component ID: 16-BFN-2111-IRS, Inside Radius Section Ultrasonic
        Examination, 16-BF-2111, Report UT-16-013, Steam Generator #11,
        (Summary #204201) [Observed]
Component 4-PRN-1100-IRS, Pressurizer Relief Nozzle, inside Radius Section,
        Ultrasonic Examination, (Summary #007000), UT-16-031, [Observed]
Observation of Baffle Bolt Replacement Activities
The inspectors observed electrical discharge machining activities on a baffle bolt
location. The inspectors observed the bolt hole milling activities for a baffle bolt. The
inspectors verified that bolt replacement activities were being performed in accordance
with approved procedures.
Other Augmented, License Renewal or Industry Initiative Examinations
PSEG did not schedule augmented inspections in the outage scope for 1R24.
Review of Relevant Indication(s) Evaluated and Accepted for Continued Service
PSEG did not have any originally rejectable indications since the end of their prior
outage, which were later accepted for continued use after evaluation.
Modifications, Repairs, or Replacements Consisting of Welding on Pressure Boundary
Risk Significant Systems
The inspectors reviewed Design Change Package 80092579, Salem Unit 1 - Steam
Generator (SG) Bowl Drain Repair, for SGs 11, 12, 13, and 14. This change removed
Alloy 600 and associated 82/182 weld material from each SG channel head bowl drain
plug to reduce the potential for primary water stress corrosion cracking. The inspectors
determined overall whether the modifications were completed in accordance with ASME
Section XI as a repair/replacement activity. Specifically, the inspectors reviewed the
machining and welding procedures used to complete the modifications, reviewed the
training of the machinists, welders and laborers qualified on a mockup of the channel
heads, and reviewed the mockup training completed by all craft personnel on the project.
The inspectors reviewed the in-process NDE and the final NDE procedures to determine
whether the change was implemented in accordance with ASME Section XI
repair/replacement requirements.
                                          10
PWR Vessel Upper Head Penetration Inspection Activities (Section 02.02)
The Salem Unit 1 reactor pressure vessel head was replaced with an Alloy 690 head in
2005. The inspectors determined that reactor pressure vessel head examinations (per
ASME Code Case N-729) were not required during 1R24.
Boric Acid Corrosion Control Inspection Activities (Section 02.03)
The inspectors reviewed the Boric Acid Corrosion Control program and implementing
PSEG procedures, and discussed the outage inspections with program engineers. The
inspectors also reviewed documentation, corrective action process notifications,
including photographic records, of the conditions identified during the plant shutdown.
The inspectors also reviewed a sample of notifications recommending repairs to
identified conditions and a sample of boric acid engineering evaluations performed to
determine the priority of repair of identified boric acid corrosion on safety significant
piping and components. Boric acid inspections were conducted on safety significant
piping and components inside the containment structure during walk downs conducted
by PSEG staff with the plant at normal pressure and temperature conditions. The
inspectors reviewed a sample of photos and visual inspection records to verify that boric
acid leakage was being appropriately identified and non-conforming conditions of boric
acid leaks were documented in the CAP with a focus on areas that could cause
degradation of safety significant components.
The inspectors verified that potentially more significant boric acid deficiencies were
being adequately dispositioned by reviewing a sample of evaluations documented in the
following PSEG condition reports: 20682192, 20699859, 20699820, 20699910,
20704139, 20707125, 20712774, 20713572, 20722494, 20682192, 20699859,
20707125, 20722494, 70179375, 20699820, 20704139, 70185980, 20712774,
20713573, 20713572.
These reviews verified whether the corrective actions were consistent with the
requirements of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI. The
inspectors reviewed the engineering evaluations associated with these condition reports
to verify whether equipment or components wetted or impinged upon by boric acid
solutions were properly analyzed for degradation that might impact their function.
Steam Generator Tube Inspection Activities (Section 02.04)
PSEGs Base Eddy Current Test (ECT) program consisted of: (a) 100 percent bobbin
probe inspection of straight and U-bend tubes, (b) 50 percent Hot Leg coverage of Top
of Tubesheet area with an array probe, (c) 3 tube periphery tube array testing, and
various + Point sampling strategies (for U-bend and Dent/Ding inspections) of in-service
tubes were completed in each SG. The inspectors reviewed the 1R24 SG tube
Degradation Assessment, ECT examination scope and expansion criteria to verify that it
met TS requirements, Electric Power Research Institute (EPRI) guidelines, and
commitments made to the NRC. The inspectors also verified that the ECT scope
included areas of degradation that were known to represent potential ECT challenges
such as the top of tube sheet, tube support plates, and U-bends. Upon completion of
eddy current (EC) examinations and the evaluation of all data, PSEG staff determined
that six tubes required plugging. The affected tubes were plugged during 1R24. The
                                          11
inspectors verified that the affected tubes were properly screened against the in situ
screening criteria and that none of the tube indications required in-situ pressure testing.
The inspectors observed portions of the ECT being performed and verified whether:
(1) the appropriate probes were used for identifying the expected types of degradation,
(2) calibration requirements were adhered to, and (3) probe travel speed was in
accordance with procedural requirements. The inspectors performed a review of the
site-specific qualifications for the techniques being used, and verified whether the ECT
data analyses were adequately performed per EPRI and PSEG specific guidelines. The
inspectors selected a sample of degraded tubes and compared them to the previous
outage operational assessment to assess PSEGs prediction capabilities. The inspectors
also reviewed a sample of EC data, and verified, through discussion with the data
analyst that the analytical techniques used to evaluate the inspection data were
adequate. The inspectors further verified that the assumed NDE flaw sizing accuracy
was consistent with data from EPRI examination technique specification sheet or
applicable performance demonstration. Finally, the inspectors reviewed the
qualifications for the EC data collection personnel, a sample of the inspection
supervision personnel qualifications and a sample of the qualifications of staff
responsible for interpretation and resolution analysis to determine whether the records
were complete.
The inspectors observed a portion of a plug integrity visual examination per procedure
81DP-9RC40, Steam Generator Channel Head Video Inspection, to verify that those
tubes that had been previously plugged did not exhibit any leakage. No evidence of plug
leakage was identified. Additionally, the inspectors observed a portion of the secondary
sludge lancing and foreign object search and retrieval (FOSAR) inspections. No
significant foreign materials or quantity of sludge were identified.
During the prior operating cycle previous to the current refueling outage 1R24, the
inspectors determined whether leakage from each SG was measured, via sampling of
each SG, for the complete prior operating cycle (leakage was not measured).
PSEG staff completed secondary side inspections and sludge lancing of all SGs. The
inspectors reviewed the results to determine that no loose parts affecting tube integrity
were noted and that other SG related inspections were performed without repairs.
PSEG staff performed a plug integrity visual examination to verify that those tubes that
had been previously plugged did not exhibit leakage. From this visual exam, PSEG staff
documented excessive boron buildup around tube plug 43-34 in the SG 11 cold leg and
initiated CR-2016-29172 to track the evaluation of the condition. PSEG staff also
initiated Notification 20726743 to track the condition. PSEG Engineering staff review of
the plug concluded that no evidence of plug leakage had occurred. Additionally,
secondary sludge lancing and FOSAR inspections were performed in each SG. No
foreign materials, which could damage SG tubes, were identified. The inspectors
reviewed the PSEG evaluations and information to determine the conclusions were
technically supported.
Identification and Resolution of Problems (Section 02.05)
The inspectors reviewed a sample of condition reports, which identified NDE indications,
deficiencies and other nonconforming conditions since the previous, 1R23, refueling
outage. The inspectors verified that nonconforming conditions were properly identified,
                                                12
      characterized, evaluated, corrective actions identified and dispositioned, and
      appropriately entered into the CAP.
b.    Findings
      Introduction. The inspectors determined the level of degradation of Unit 1 baffle bolts
      reported to the NRC as a condition not previously analyzed is an issue of concern that
      warrants additional inspection to determine whether a performance deficiency exists. As
      a result, the NRC opened a unresolved item (URI).
      Description. Additional inspection is warranted to determine whether a performance
      deficiency exists related to Event Notification 51902, dated May 3, 2016, in which PSEG
      reported to the NRC that the level of degradation of baffle bolts was a condition not
      previously analyzed. The baffle bolts secure plates in the reactor core barrel to form a
      shroud around the fuel core to direct reactor coolant flow upward through the fuel
      assemblies. In order to determine if a performance deficiency exists, the inspectors will
      review the results of PSEGs RCE which will be completed at a later date.
      (URI 05000272/2016002-01, Baffle-Former Bolts with Identified Anomalies)
1R11 Licensed Operator Requalification Program (71111.11Q - 1 sample)
      Quarterly Review of Licensed Operator Requalification Testing and Training
    a. Inspection Scope
      The inspectors observed licensed operator simulator training on June 8, 2016, which
      included a heater drain pump oil leak, a steam generator feed pump trip, and a steam
      generator tube rupture. The inspectors evaluated operator performance during the
      simulated event and verified completion of risk significant operator actions, including the
      use of abnormal and emergency operating procedures. The inspectors assessed the
      clarity and effectiveness of communications, implementation of actions in response to
      alarms and degrading plant conditions, and the oversight and direction provided by the
      control room supervisor. The inspectors verified the accuracy and timeliness of the
      emergency classification made by the shift manager and the TS action statements
      entered by the shift technical advisor. Additionally, the inspectors assessed the ability of
      the crew and training staff to identify and document crew performance problems.
    b. Findings
      No findings were identified.
1R12 Maintenance Effectiveness (71111.12Q - 3 samples)
    a. Inspection Scope
      The inspectors reviewed the samples listed below to assess the effectiveness of
      maintenance activities on SSC performance and reliability. The inspectors reviewed
      system health reports, CAP documents, maintenance WOs, and maintenance rule (MR)
      basis documents to ensure that PSEG was identifying and properly evaluating
      performance problems within the scope of the MR. For each sample selected, the
      inspectors verified that the SSC was properly scoped into the MR in accordance with
                                                13
      10 CFR 50.65 and verified that the (a)(2) performance criteria established by PSEG staff
      was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed
      the adequacy of goals and corrective actions to return these SSCs to (a)(2).
      Additionally, the inspectors ensured that PSEG staff was identifying and addressing
      common cause failures that occurred within and across MR system boundaries.
        Unit 2, 22SW535, unsatisfactory stroke time of SW accumulator supply valve to
          22 containment fan cooler unit (CFCU) on May 2
        Unit 2, Circulating water system 125V DC battery degradation on May 23
        Common, MR URI, 05000272;311/2015008-01: Inadequate MR System
          Performance Criteria Selection, closeout on May 1
  b. Findings
      No findings were identified. Additional inspection results regarding the URI closeout are
      documented in Section 4OA5.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 5 samples)
  a. Inspection Scope
      The inspectors reviewed station evaluation and management of plant risk for the
      maintenance and emergent work activities listed below to verify that PSEG performed
      the appropriate risk assessments prior to removing equipment for work. The inspectors
      selected these activities based on potential risk significance relative to the reactor safety
      cornerstones. As applicable for each activity, the inspectors verified that PSEG
      personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the
      assessments were accurate and complete. When PSEG performed emergent work, the
      inspectors verified that operations personnel promptly assessed and managed plant risk.
      The inspectors reviewed the scope of maintenance work and discussed the results of
      the assessment with the stations probabilistic risk analyst to verify plant conditions were
      consistent with the risk assessment. The inspectors also reviewed the TS requirements
      and inspected portions of redundant safety systems, when applicable, to verify risk
      analysis assumptions were valid and applicable requirements were met.
        Unit 1, 11SW223, SW outlet valve to 11 CFCU, failure to close on April 7
        Unit 1, Reactor core baffle-to-former bolt expanded inspection scope on April 22
        Unit 2, Appendix R safe shutdown panel failed indication on May 9
        Unit 2, 2A subcooling margin monitor failure on May 26
        Unit 2, Yellow risk with one offsite power source unavailable on June 1
  b. Findings
      No findings were identified.
                                                14
1R15 Operability Determinations and Functionality Assessments (71111.15 - 9 samples)
  a. Inspection Scope
      The inspectors reviewed operability determinations for the following degraded or
      non-conforming conditions based on the risk significance of the associated components
      and systems:
        Unit 1, Corrosion and metal loss identified during inspection of 11 SW header
              on April 23
        Unit 1, Immediate operability determination (IOD) of the degraded condition of the
              baffle-former bolts on April 27
        Unit 1, 1 Emergency control air compressor shutdown on April 27
        Unit 1, SI thermal relief valve failures on May 2
        Unit 1, 13 turbine-driven auxiliary feedwater (AFW) pump degraded performance
              on May 8
        Unit 1, 11 diesel fuel oil storage tank high particulates on May 18
        Unit 2, IOD of the degraded condition of the baffle-former bolts identified from Unit 1
            operating experience on April 27
        Unit 2, 125V DC battery degraded cell post connections on May 2
        Common, 10 CFR Part 21 issue related to safety-related 4kV breakers on May 16
      The inspectors evaluated the technical adequacy of the operability determinations to
      assess whether TS operability was properly justified and the subject component or
      system remained available such that no unrecognized increase in risk occurred. The
      inspectors compared the operability and design criteria in the appropriate sections of the
      TSs and UFSAR to PSEGs evaluations to determine whether the components or
      systems were operable. The inspectors confirmed, where appropriate, compliance with
      bounding limitations associated with the evaluations. Where compensatory measures
      were required to maintain operability, the inspectors determined whether the measures
      in place would function as intended and were properly controlled by PSEG.
  b. Findings
      Introduction. The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B,
      Criterion V, "Instructions, Procedures, and Drawings," because, from June 15, 2016
      until July 26, 2016, PSEG did not accomplish actions necessary to provide adequate
      confidence that an SSC would perform satisfactorily in service (an activity affecting
      quality) as prescribed by a documented procedure. Specifically, although PSEG had
      concluded Salem Unit 2 is susceptible to baffle bolt failure due to its design and
      operating life (but less susceptible than Salem Unit 1), PSEG inadequately implemented
      Procedure OP-AA-108-115, "Operability Determinations & Functionality Assessments,"
      by not performing Section 4.7.14 followed by Sections 4.7.18-4.7.20 to perform an
      operability evaluation (OpEval) to justify continued operation of the unit until the next
      refueling outage. In particular, PSEG incorrectly exited their procedure on June 15,
      2016, and re-entered it to complete these steps on July 26, 2016, based on discussions
      with the NRC. The operability evaluation provided appropriate justification for the
      licensees plans to examine the baffle-former bolts at the next Unit 2 RFO.
                                            15
Description. On April 22, 2016, PSEG identified baffle-former (baffle) bolt degradation
at Salem Unit 1 that was determined to be unanalyzed because it did not meet the
minimum acceptable bolt pattern analysis developed to support plant startup. PSEG
staff identified that 192 baffle bolts out of a total population of 832 were considered
degraded. On May 4, 2016, due to the number of degraded baffle bolts discovered on
Unit 1, PSEG staff determined that it was necessary to perform an extent of condition
review for the baffle bolts on Unit 2. PSEG entered this issue into the corrective action
program as NOTF 20727590 and completed an immediate operability determination
(IOD) to evaluate the Unit 2 baffle bolts and baffle assembly structure in accordance with
PSEG procedure OP-AA-108-115, "Operability Determinations & Functionality
Assessments," Section 4.7.4.
The inspectors reviewed the design basis and current licensing basis documents for
Unit 2 to identify the specific safety functions of the baffle bolts. The inspectors identified
that the baffle bolts are part of the baffle assembly structure located in the reactor
pressure vessel. The bolts secure a series of vertical metal plates called baffle plates,
which help direct water up through the nuclear fuel assemblies to ensure proper cooling
of the fuel. A sufficient number of baffle bolts are required to secure the plates to ensure
proper core flow during normal and postulated accident conditions, and also to ensure
that control rods can be inserted to shut down the reactor.
On June 21, 2016, the inspectors reviewed the IOD as part of a detailed review of the
ongoing baffle bolt activities at Salem and noted that the IOD concluded that there was
reasonable assurance that the Unit 2 reactor assembly was operable, but required
additional evaluation due to the conditions observed in Unit 1. Specifically, the IOD
concluded that there was reasonable assurance that the Unit 2 reactor assembly was
operable pending further evaluation based upon the following factors: (1) Unit 2 had
fewer effective full power years of operation than Unit 1; (2) a baffle bolt visual
examination completed during the most recent Unit 2 2R21 refueling outage (fall 2015)
did not identify any visual deficiencies; and, (3) there was no current indication of reactor
fuel pin leakage in Unit 2, which could be caused by baffle bolt failure and subsequent
fretting. The inspectors review of PSEGs IOD concluded that the IOD provided
sufficient technical detail to support the initial conclusion that there was reasonable
assurance, based on the limited information available, that the Unit 2 baffle bolts would
retain sufficient capability to perform their intended functions. PSEG procedure OP-AA-
108-115, Section 4.7.11 directs that if there is a reasonable expectation that the SSC is
operable, but a more rigorous evaluation is deemed warranted, then update the current
notification or initiate a notification for Engineering to prepare a Technical Evaluation to
support the prompt determination of operability. The immediate actions section of
NOTF 20727590 requested a work order be generated to perform an extent of condition
review for Unit 2 baffle bolts. The Station Ownership Committee (SOC) screening of
NOTF 20727590 on May 6, 2016, assigned a work order to Engineering to ensure that
Operations is provided the Technical Evaluation product. This will allow review for
assessment of operability as required. From review of the daily running log of baffle
bolt action items spreadsheet, the inspectors noted that on May 4, 2016, action EOC.2
to perform an operability evaluation for Unit 2 was closed to EOC.7-9, to complete an
adverse condition monitoring plan, an operational decision making document, and a
Technical Evaluation in lieu of an OpEval. Consistent with this decision, on May 26,
2016, the Salem plant manager discussed with the senior resident inspector PSEGs
views that an operability evaluation was not required or being developed. In response,
                                            16
the inspectors shared their understanding of PSEG procedure guidance and regulatory
requirements in this regard.
Between May 6 and June 15, 2016, PSEG engineering performed Technical Evaluation
70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt
Failure. The purpose of the Technical Evaluation was to determine the potential for
baffle bolt degradation in Unit 2 based upon the results of visual and ultrasonic
examination results observed in Unit 1, and to identify and evaluate key factors that
could potentially impact the safe operation of Unit 2 for the remainder of the current
operating cycle. The Technical Evaluation evaluated the key factors that affect
irradiation assisted stress corrosion cracking (IASCC). Additionally, the Technical
Evaluation assessed the safety consequences of the degraded baffle bolts in the as-
found condition in Unit 1. The Technical Evaluation conclusion summary indicated that
Unit 2 is susceptible to baffle bolt failure due to its design and operating life; that any
degradation in Unit 2 would be less advanced that that observed in Unit 1; and that
PSEG should exercise heightened awareness and monitoring of Unit 2 due to this
vulnerability. The Technical Evaluation also concluded that Unit 1 could have safely
shut down and the core would be cooled by demonstrating that control rod insertability is
assured and a core coolable geometry was maintained. Thus the Technical Evaluation
concluded that Unit 2 could also be shut down and cooled based upon the conclusion
reached regarding Unit 1. Following completion of the Technical Evaluation on June 15,
PSEG did not continue on in the operability determination process.
The inspectors assessed PSEGs Technical Evaluation 70187161 during an onsite
inspection which took place from June 21-23, 2016. PSEG concluded in Technical
Evaluation 70187161, that Salem Unit 2 is susceptible to baffle bolt failure due to its
design and operating history, but less so than observed in Salem Unit 1. The inspectors
determined this conclusion met PSEGs definition of a degraded condition as defined in
procedure OP-AA-115-108, Section 2.4. Section 2.4 defines a degraded condition as A
condition in which the qualification of an SSC or its functional capability is reduced.
Section 2.4 lists reduced reliability as an example of a degraded condition and aging
as an example of a condition that can reduce the capability of a system. The inspectors
noted that IASCC is a time dependent aging degradation mechanism and baffle bolt
failures reduce the functional capability and reliability of the baffle assembly.
Consequently the Technical Evaluation describes a degraded condition in the Unit 2
baffle assembly. Since the Technical Evaluation concluded that the reactor could be
shut down and cooled based upon the assessment of safety consequences, the
inspectors concluded that PSEG considered that the reactivity control and emergency
core cooling systems were operable. As a result, the inspectors concluded that PSEG
should have continued on in the operability determination process as described in
Section 4.7.14, Operable but Degraded or Nonconforming, and declared both the
reactivity control and emergency core cooling systems operable but degraded. Once a
SSC is determined to be operable but degraded, Section 4.7.18 directs that An
OpEval will be requested based on a declaration of operable but degraded or
nonconforming. Section 4.7.19 directs Engineering to Prepare and review and
OpEval. Section 4.7.20 directs Operations to approve or disapprove the OpEval when
Engineering completes it. Sections 4.7.14, 4.7.18, 4.7.19 and 4.7.20 were not
implemented by PSEG.
The inspectors acknowledged that licensees apply judgment in these decisions and can
use a graded approach regarding the level of detail. In this particular instance, the
                                          17
inspectors considered that operating experience was available that showed the Unit 2
baffle bolts were subject to IASCC and that plants of similar design (4-loop
Westinghouse pressurized water reactors with a down-flow configuration and baffle bolts
of 347 stainless steel material and similar dimensions) were subject to greater amounts
of bolt degradation compared to other reactor designs. Furthermore, the inspectors
noted the baffle bolts had experienced levels of neutron radiation exposure above the
threshold for IASCC initiation as referenced in NUREG/CR-7027, Degradation of LWR
Core Internal Materials due to Neutron Irradiation.
The inspectors conducted an exit meeting on June 23, 2016, describing a potential
violation of 10 CFR Part 50 Appendix B, Criterion 5, Instructions, Procedures, and
Drawings, for PSEG not completing the OpEval and assessing the effect of the
operability of the ECCS and rod control system based upon the functionality of the baffle
former assembly. Consistent with the change made by PSEG staff to the Salem action
item list on May 4, 2016, to not perform an OpEval, the PSEG Compliance Director
indicated that an operability evaluation was not required and therefore they disagreed
with this finding.
The inspectors determined that Engineering did not perform an OpEval as directed by
OP-AA-108-115 Section 4.7.19, which states PREPARE and REVIEW an OpEval. The
OpEval Form (Attachment 1), or a facsimile, may be used to document the engineering
evaluation (Engineering). Because an OpEval was not prepared, Operations did not
have the opportunity to approve or disapprove an OpEval as required by
OP-AA-108.115, Section 4.7.20 which states: When Engineering completes the
OpEval, then APPROVE or DISAPPROVE.
In summary, Technical Evaluation 70187161 concluded Unit 2 is susceptible to IASCC
baffle bolt degradation and that the expected degradation should be less than that
observed in Unit 1. The inspectors assessed that PSEGs conclusions concerning the
susceptibility and expected degradation in Unit 2 was adequately supported. However,
the inspectors concluded that the Technical Evaluation did not provide adequate
confidence that SSCs (baffle bolts supporting ECCS) would perform satisfactorily in
service to justify continued operation of Unit 2 until the next refueling outage in the
spring of 2017 in that line break size assumptions were not adequately supported.
Following discussions with NRC Region I management and the inspectors, PSEG staff
subsequently completed an operability evaluation (OpEval 2016-015) on July 26, 2016.
The OpEval compared the differences in the operating history and parameters between
Unit 1 and Unit 2 and again concluded that Unit 2 was less susceptible than Unit 1
primarily due to significantly fewer thermal cycles and fewer effective full power years
(EFPY) of operation. The OpEval concluded that operability was supported although
the Unit 2 baffle assemblies are considered degraded since Unit 2 is susceptible to
degraded baffle bolts. Based upon a qualitative analysis, PSEGs OpEval stated that
Unit 2 can accommodate 38 percent degraded baffled-former bolts (distributed across
the assembly) and remain within the acceptable bolting pattern analysis patterns
assuming the dynamic loads of a large break loss of coolant accident. The inspectors
concluded that PSEGs OpEval 2016-015 provided an adequate basis to conclude that
the Unit 2 baffle assembly would support ECCS and rod control system continued
operation until the planned refueling outage in spring 2017. In particular, the inspectors
considered that PSEGs visual examinations of approximately 70 percent of the baffle
bolts, in the fall 2015 refueling outage (2R21), did not identify any bolts that were
                                            18
missing or visually degraded. Considering the collective results from Salem Unit 1 and 2
baffle bolt visual examination results, the inspectors determined this evidence, in
conjunction with a review of other operating factors (EFPY and thermal cycles), provided
a reasonable expectation of the Salem Unit 2 baffle assemblys capability to perform its
supporting TS functions.
Analysis. The inspectors determined that a performance deficiency resulted when PSEG
did not implement Procedure OP-AA-108-115, "Operability Determinations &
Functionality Assessments," Section 4.7.14 followed by Sections 4.7.18-4.7.20 to
perform an OpEval to justify continued operation of the unit until the next refueling
outage for the Unit 2 baffle bolt degraded condition until questioned by NRC inspectors.
PSEGs initial documentation did not provide sufficient basis for continued operation until
the next refueling outage. Specifically, based upon the Technical Evaluation 70187161
conclusion that the Salem Unit 2 design and operating life make it susceptible to baffle
bolt failures, the inspectors determined that PSEG, in effect, concluded that a degraded
condition exists in Unit 2. Therefore, PSEG should have continued on in the operability
determination process as described in Section 4.7.14, Operable but Degraded or
Nonconforming.
This finding is more than minor because it is associated with the equipment performance
attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences, in that, degradation of a significant
number of baffle bolts could result in baffle plates dislodging following an accident. This
issue was dispositioned as more than minor because it was also similar to example 3.j of
IMC 0612, Appendix E, Examples of Minor Issues, in that, the condition resulted in
reasonable doubt of operability of the ECCS and additional analysis was necessary to
verify operability. In accordance with IMC 0609.04, Initial Characterization of Findings,
and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for
Findings At-Power, issued June 19, 2012, the inspectors screened the finding for safety
significance and determined it to be of very low safety significance (Green), since the
finding did not represent an actual loss of system or function. After inspector
questioning, PSEG performed OpEval 2016-015, which provided sufficient bases to
conclude the Unit 2 baffle assembly would support ECCS and control rod system
operability until the next RFO. This finding is related to the cross-cutting aspect of
Operating Experience because PSEG did not effectively evaluate relevant internal and
external operating experience. Specifically, PSEG did not adequately evaluate the
impact of degraded baffle bolts at Unit 2 when directly relevant operating experience
was identified at Unit 1. [P.5]
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, states, in part, that activities affecting quality shall be prescribed by
documented procedures of a type appropriate to the circumstances and shall be
accomplished in accordance with those procedures. The Introduction to Appendix B
states that quality assurance comprises all those planned and systematic actions
necessary to provide adequate confidence that a SSC will perform satisfactorily in
service. PSEG Procedure OP-AA-108-115, "Operability Determinations & Functionality
Assessments," prescribes PSEGs process to assess the operability of SSCs that are
required to be operable by TSs, or that perform required support functions for SSCs that
are required to be operable by TSs. Section 4.7 prescribes the operability determination
process. Section 4.7.14 states that if an SSC described in TSs is determined to be
                                                19
      operable even though a degraded or nonconforming condition is present, then the SSC
      is considered operable but degraded or nonconforming. Sections 4.7.18 - 4.7.20
      describe how the Operations Shift Manager should request the site engineering staff to
      perform an OpEval upon a declaration of operable but degraded, or nonconforming.
      The OpEval is completed to justify continued operation during the period of time while
      operable but degraded or nonconforming conditions exist.
      Contrary to the above, from June 15, 2016, until July 26, 2016, PSEG did not
      accomplish actions necessary to provide adequate confidence that an SSC would
      perform satisfactorily in service (an activity affecting quality) as prescribed by a
      documented procedure. Specifically, although PSEG had concluded the Salem Unit 2
      design and operating life make it susceptible to baffle former bolt failures, PSEG
      inadequately implemented Procedure OP-AA-108-115, to perform an OpEval to justify
      continued operation of the unit. PSEGs corrective actions included entering the issue
      into its corrective action program (NOTF 20736630) and documenting an adequate
      operability evaluation (OpEval 2016-015 on July 26, 2016) to support the basis for
      functionality of the baffle structure and its ability to support the operability of the ECCS
      and reactivity control systems. This violation is being treated as an NCV, consistent with
      Section 2.3.2 of the Enforcement Policy. (NCV 05000311/2016002-02, Failure to
      Follow Operability Determination Procedure for Unit 2 Baffle-Former Bolts)
1R18 Plant Modifications (71111.18 - 2 samples)
.2    Permanent Modifications
  a. Inspection Scope
      The inspectors reviewed Design Change Package (DCP) 80117136, Salem Unit 1
      Baffle to Former Bolt Replacement. This modification documents the replacement of
      189 degraded and potentially degraded baffle bolts with a new design baffle bolt made of
      an improved material. Additionally the modification documented the locations of the
      replacement bolts and the location of three degraded or potentially degraded bolts which
      were left in place and are described below. The inspectors also reviewed modification
      documents (DCP 80117378) associated with the equivalency evaluation of the material
      change from Type 347 stainless steel to Type 316 stainless steel, and the bolt head
      design change from a slot to a hex configuration. Thus this inspection involved two
      samples - 1) the bolting pattern analysis for the replacement bolts, and 2) a review of
      the bolting material change.
      This modification was completed during the spring 2016 refueling outage (1R24) and
      involved the replacement of 189 baffle bolts out of a total of 832 located in the Unit 1
      reactor vessel. PSEG replaced 189 either degraded or potentially degraded baffle bolts
      as observed by visual indications of missing or protruding bolt heads, missing or broken
      lock bar, bolts that did not pass ultrasonic testing or bolts that were inaccessible for
      ultrasonic testing. PSEG did not remove and replace three bolts that were potentially
      degraded due to difficulties encountered during the removal/replacement process. One
      bolt had an indication during ultrasonic testing but was not visibly damaged. The second
      bolt was inaccessible for ultrasonic testing, which would have required replacement.
      The third bolt had successfully passed an ultrasonic test but had a visual indication on
      one of the lock bar welds which may have indicated a crack in the weld.
                                                20
      The inspectors reviewed PSEGs analysis and the Westinghouse minimum bolting
      analysis and determined that leaving the one degraded and two potentially degraded
      bolts installed was technically acceptable and that the baffle assembly was functional as
      a system support component. Details of the NRC assessment of the final configuration
      of the baffle bolts and the minimum bolting analysis can be found in Section 4OA2 of this
      report.
  b. Findings
      No findings were identified.
1R19 Post-Maintenance Testing (71111.19 - 9 samples)
  a. Inspection Scope
      The inspectors reviewed the post-maintenance tests for the maintenance activities listed
      below to verify that procedures and test activities adequately tested the safety functions
      that may have been affected by the maintenance activity, that the acceptance criteria in
      the procedure were consistent with the information in the applicable licensing basis
      and/or design basis documents, and that the test results were properly reviewed and
      accepted and problems were appropriately documented. The inspectors also walked
      down the affected job site, observed the pre-job brief and post-job critique where
      possible, confirmed work site cleanliness was maintained, and witnessed the test or
      reviewed test data to verify quality control hold point were performed and checked,
      and that results adequately demonstrated restoration of the affected safety functions.
        Unit 1, 13 Station power transformer tap changer did not function in automatic on
              May 4
          Unit 1 11SJ45, residual heat removal (RHR) to SI motor-operated valve failure to
              stroke closed on May 5
        Unit 1, 12 containment fan cooling unit (CFCU) motor cooler HX failed leak test on
              May 6
        Unit 1, Reactor coolant pump flow channel III degraded on May 6
        Unit 1, Turbine-driven AFW room cooler cycling on May 10
        Unit 1, Reactor vessel level indication system capillary repair on May 13
        Unit 2, 24 SW strainer trip on thermal overloads on April 7
        Unit 2, 24 SG flow channel 1 drop to 93 percent on May 4
        Unit 2, 21 Chiller thermal expansion valve failure on May 24
  b. Findings
      No findings were identified.
1R20 Refueling and Other Outage Activities (71111.20 - 1 sample)
  a. Inspection Scope
      The inspectors reviewed the stations work schedule and outage risk plan for the Unit 1
      maintenance and refueling outage (1R24), conducted April 14 through the end of the
      quarter. The inspectors reviewed PSEGs development and implementation of outage
                                                  21
      plans and schedules to verify that risk, industry experience, previous site-specific
      problems, and defense-in-depth were considered. During the outage, the inspectors
      observed portions of the shutdown and cooldown processes and monitored controls
      associated with the following outage activities:
          Configuration management, including maintenance of defense-in-depth,
          commensurate with the outage plan for the key safety functions and compliance with
          the applicable TSs when taking equipment out of service
          Implementation of clearance activities and confirmation that tags were properly hung
          and that equipment was appropriately configured to safely support the associated
          work or testing
          Installation and configuration of reactor coolant pressure, level, and temperature
          instruments to provide accurate indication and instrument error accounting
          Status and configuration of electrical systems and switchyard activities to ensure that
          TSs were met
          Monitoring of decay heat removal operations
          Impact of outage work on the ability of the operators to operate the SF pool cooling
          system
          Reactor water inventory controls, including flow paths, configurations, alternative
          means for inventory additions, and controls to prevent inventory loss
          Activities that could affect reactivity
          Maintenance of secondary containment as required by TSs
          Refueling activities, including fuel handling and fuel receipt inspections
          Fatigue management
          Tracking of startup prerequisites, walkdown of the drywell (primary containment) to
          verify that debris had not been left which could block the emergency core cooling
          system suction strainers, and startup and ascension to full power operation
          Identification and resolution of problems related to refueling outage activities
          Foreign Object Search and Retrieval (FOSAR) for missing baffle bolts and locking
          tabs
      During this outage, PSEG replaced 189 degraded baffle bolts in the Unit 1 reactor vessel
      baffle assembly. This emergent project resulted in the extension of the outage schedule
      from 36 days to 106 days.
  b. Findings
      No findings were identified.
1R22 Surveillance Testing (71111.22 - 5 samples)
  a. Inspection Scope
      The inspectors observed performance of surveillance tests and/or reviewed test data of
      selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR,
      and PSEG procedure requirements. The inspectors verified that test acceptance criteria
      were clear, tests demonstrated operational readiness and were consistent with design
      documentation, test instrumentation had current calibrations and the range and accuracy
      for the application, tests were performed as written, and applicable test prerequisites
      were satisfied. Upon test completion, the inspectors considered whether the test results
                                                22
      supported that equipment was capable of performing the required safety functions. The
      inspectors reviewed the following surveillance tests:
        Unit 1, Manual SI on April 17
        Unit 1, 11CA360, control air header supply check valve, as-found local leak rate test
              (LLRT) on April 22
        Unit 2, 21 RHR In-service Testing on April 1
        Unit 2, 22SW223, SW outlet valve to 22 CFCU, stroke time in the required evaluation
                range on May 3
        Unit 2, Reactor coolant system (RCS) elevated leakrate on May 17
  b. Findings
      No findings were identified.
      Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation (71114.06 - 1 sample)
      Emergency Preparedness Drill Observation
  a. Inspection Scope
      The inspectors evaluated the conduct of a routine PSEG emergency drill on June 16 to
      identify any weaknesses and deficiencies in the classification, notification, and protective
      action recommendation development activities. The inspectors observed emergency
      response operations in the simulator, technical support center, and emergency
      operations facility to determine whether the event classification, notifications, and
      protective action recommendations were performed in accordance with procedures. The
      inspectors also attended the drill critique to compare inspector observations with those
      identified by PSEG staff in order to evaluate PSEGs critique and to verify whether the
      PSEG staff was properly identifying weaknesses and entering them into the CAP.
  b. Findings
      No findings were identified.
2.    RADIATION SAFETY
      Cornerstones: Occupational and Public Radiation Safety
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01 - 6 samples)
  a. Inspection Scope
      The inspectors reviewed PSEGs performance in assessing and controlling radiological
      hazards in the workplace. The inspectors used the requirements contained in 10 CFR
      Part 20, TSs, applicable Regulatory Guides (RGs), and the procedures required by TSs
      as criteria for determining compliance.
                                        23
Inspection Planning
The inspectors reviewed the PIs for the occupational radiation safety cornerstone,
radiation protection (RP) program audits, and reports of operational occurrences in
occupational radiation safety since the last inspection.
Radiological Hazard Assessment (1 sample)
The inspectors conducted independent radiation measurements during walk-downs of
the facility and reviewed the radiological survey program, air sampling and analysis,
continuous air monitor use, recent plant radiation surveys for radiological work activities,
and any changes to plant operations since the last inspection to verify survey adequacy
of any new radiological hazards for onsite workers or members of the public.
Instructions to Workers (1 sample)
The inspectors reviewed high radiation area work permit controls and use; observed
containers of radioactive materials and assessed whether the containers were labeled
and controlled in accordance with requirements.
The inspectors reviewed several occurrences where a workers electronic personal
dosimeter alarmed. The inspectors reviewed PSEGs evaluation of the incidents,
documentation in the CAP, and whether compensatory dose evaluations were
conducted when appropriate. The inspectors verified follow-up investigations of actual
radiological conditions for unexpected radiological hazards were performed.
Contamination and Radioactive Material Control
The inspectors observed the monitoring of potentially contaminated material leaving the
radiological controlled area and inspected the methods and radiation monitoring
instrumentation used for control, survey, and release of that material.
Radiological Hazards Control and Work Coverage (1 sample)
The inspectors evaluated in-plant radiological conditions and performed independent
radiation measurements during facility walk-downs and observation of radiological work
activities. The inspectors assessed whether posted surveys; radiation work permits
(RWPs); worker radiological briefings and RP job coverage; the use of continuous air
monitoring, air sampling, and engineering controls; and dosimetry monitoring were
consistent with the present conditions. The inspectors examined the control of highly
activated or contaminated materials stored within the SF pools and the posting and
physical controls for selected high radiation areas (HRAs), locked high radiation areas
(LHRAs) and very high radiation areas (VHRAs) to verify conformance with the
occupational PI.
Risk-Significant High Radiation Area and Very High Radiation Area Controls (1 sample)
The inspectors reviewed the procedures and controls for HRAs, VHRAs, and radiological
transient areas in the plant.
                                              24
      Radiation Worker Performance and Radiation Protection Technician Proficiency
      (1 sample)
      The inspectors evaluated radiation worker performance with respect to RP work
      requirements. The inspectors evaluated RP technicians in performance of radiation
      surveys and in providing radiological job coverage.
      Problem Identification and Resolution (1 sample)
      The inspectors evaluated whether problems associated with radiation monitoring and
      exposure control (including operating experience) were identified at an appropriate
      threshold and properly addressed in the CAP.
  b. Findings
      No findings were identified.
2RS2 Occupational As Low As is Reasonable Achievable Planning and Controls
      (71124.02 - 3 samples)
  a. Inspection Scope
      The inspectors assessed PSEGs performance with respect to maintaining occupational
      individual and collective radiation exposures as low as is reasonably achievable
      (ALARA). The inspectors used the requirements contained in 10 CFR Part 20,
      applicable RGs, TSs, and procedures required by TSs as criteria for determining
      compliance.
      Inspection Planning
      The inspectors conducted a review of Salem Station collective dose history and trends;
      ongoing and planned radiological work activities; previous post-outage ALARA reviews;
      radiological source term history and trends; and ALARA dose estimating and tracking
      procedures.
      Radiological Work Planning
      The inspectors selected the following radiological work activities based on exposure
      significance for review:
            RWP 13, Control Rod Drive Activities
            RWP 14 , Pressurizer Activities
            RWP 17, Primary SG Work
      For each of these activities, the inspectors reviewed: ALARA work activity evaluations;
      exposure estimates; and exposure reduction requirements.
                                              25
      Verification of Dose Estimates and Exposure Tracking Systems
      The inspectors reviewed the current annual collective dose estimate; basis methodology;
      and measures to track, trend, and reduce occupational doses for ongoing work activities.
      The inspectors evaluated the adjustment of exposure estimates or re-planning of work.
      Source Term Reduction and Control (1 sample)
      The inspectors reviewed the current plant radiological source term and historical trend,
      plans for plant source term reduction, and contingency plans for changes in the source
      term as the result of changes in plant fuel performance or changes in plant primary
      chemistry.
      The inspectors observed radiological work activities and evaluated the use of shielding
      and other engineering work controls based on the radiological controls and ALARA plans
      for those activities.
      Radiation Worker Performance (1 sample)
      The inspectors observed radiation worker and RP technician performance during
      radiological work to evaluate worker ALARA performance according to specified work
      controls and procedures. Workers were interviewed to assess their knowledge and
      awareness of planned and/or implemented radiological and ALARA work controls.
      Problem Identification and Resolution (1 sample)
      The inspectors evaluated whether problems associated with ALARA planning and
      controls were identified at an appropriate threshold and properly addressed in the CAP.
  b. Findings
      No findings were identified.
2RS3 In-Plant Airborne Radioactivity Control and Mitigation (71124.03 - 3 samples)
  a. Inspection Scope
      The inspectors reviewed the control of in-plant airborne radioactivity and the use of
      respiratory protection devices in these areas. The inspectors used the requirements in
      10 CFR Part 20, RG 8.15, RG 8.25, NUREG/CR-0041, TS, and procedures required by
      TS as criteria for determining compliance.
      Inspection Planning
      The inspectors reviewed the UFSAR to identify ventilation and radiation monitoring
      systems associated with airborne radioactivity controls and respiratory protection
      equipment staged for emergency use. The inspectors also reviewed respiratory
      protection program procedures and current PIs for unintended internal exposure
      incidents.
                                                26
      Engineering Controls (1 sample)
      The inspectors reviewed operability and use of both permanent and temporary
      ventilation systems, and the adequacy of airborne radioactivity radiation monitoring in
      the plant based on location, sensitivity, and alarm set-points.
      Use of Respiratory Protection Devices (1 sample)
      The inspectors reviewed the adequacy of PSEGs use of respiratory protection devices
      in the plant to include applicable ALARA evaluations, respiratory protection device
      certification, respiratory equipment storage, air quality testing records, and individual
      qualification records.
      Problem Identification and Resolution (1 sample)
      The inspectors evaluated whether problems associated with the control and mitigation of
      in-plant airborne radioactivity were identified at an appropriate threshold and addressed
      by PSEGs CAP.
  b. Findings
      No findings were identified.
2RS4 Occupational Dose Assessment (71124.04 - 2 samples)
  a. Inspection Scope
      The inspectors reviewed the monitoring, assessment, and reporting of occupational
      dose. The inspectors used the requirements in 10 CFR Part 20, RGs, TSs, and
      procedures required by TSs as criteria for determining compliance.
      Inspection Planning
      The inspectors reviewed: RP program audits; National Voluntary Laboratory
      Accreditation Program (NVLAP) dosimetry testing reports; and procedures associated
      with dosimetry operations.
      Source Term Characterization (1 sample)
      The inspectors reviewed the plant radiation characterization (including gamma, beta,
      alpha, and neutron) being monitored. The inspector verified the use of scaling factors to
      account for hard-to-detect radionuclides in internal dose assessments.
      External Dosimetry
      The inspectors reviewed: dosimetry NVLAP accreditation; onsite storage of dosimeters;
      the use of correction factors to align electronic personal dosimeter results with NVLAP
      dosimetry results; dosimetry occurrence reports; and CAP documents for adverse trends
      related to external dosimetry.
                                              27
      Internal Dosimetry (1 sample)
      The inspectors reviewed: internal dosimetry procedures; whole body counter
      measurement sensitivity and use; adequacy of the program for whole body count
      monitoring of plant radionuclides or other bioassay technique; adequacy of the program
      for dose assessments based on air sample monitoring and the use of respiratory
      protection; and internal dose assessments for any actual internal exposure.
      Special Dosimetric Situations
      The inspectors reviewed external dose monitoring of workers in large dose rate gradient
      environments.
      Problem Identification and Resolution
      The inspectors evaluated whether problems associated with occupational dose
      assessment were identified at an appropriate threshold and properly addressed in the
      CAP.
  b. Findings
      No findings were identified.
2RS5 Radiation Monitoring Instrumentation (71124.05 - 1 sample)
  a. Inspection Scope
      The inspectors reviewed performance in assuring the accuracy and operability of
      radiation monitoring instruments used to protect occupational workers during plant
      operations and from postulated accidents. The inspectors used the requirements in
      10 CFR Part 20; RGs; applicable industry standards; and procedures required by TSs as
      criteria for determining compliance.
      Inspection Planning
      The inspectors reviewed: Salem Station UFSAR; RP audits; records of in-service survey
      instrumentation; and procedures for instrument source checks and calibrations.
      Walkdowns and Observations
      The inspectors checked the calibration and source check status of various portable
      radiation survey instruments and contamination detection monitors for personnel and
      equipment.
      Calibration and Testing Program
      The inspectors reviewed the calibration standards used for portable instrument
      calibrations and response checks to verify that instruments were calibrated by a facility
      that used National Institute of Science and Technology traceable sources.
                                                28
      Problem Identification and Resolution (1 sample)
      The inspectors verified that problems associated with radiation monitoring
      instrumentation (including failed calibrations) were identified at an appropriate threshold
      and properly addressed in the CAP.
  b. Findings
      No findings were identified.
      Cornerstone: Public Radiation Safety (PS)
2RS7 Radiological Environmental Monitoring Program (71124.07 - 2 samples)
  a. Inspection Scope
      The inspectors reviewed the Radiological Environmental Monitoring Program (REMP) to
      validate the effectiveness of the radioactive gaseous and liquid effluent release program
      and implementation of the Groundwater Protection Initiative (GPI). The inspectors used
      the requirements in 10 CFR Part 20; 40 CFR Part 190; 10 CFR Part 50, Appendix I; TSs;
      Offsite Dose Calculation Manual (ODCM); Nuclear Energy Institute 07-07; and
      procedures required by TSs as criteria for determining compliance.
      Inspection Planning
      The inspectors reviewed: Salem and Hope Creek Stations 2015 annual radiological
      environmental and effluent monitoring reports; REMP program audits; ODCM changes;
      land use census; UFSAR; and inter-laboratory comparison program results.
      Site Inspection (1 sample)
      The inspectors walked down various passive dosimeter and air and water sampling
      locations and reviewed associated calibration and maintenance records. The inspectors
      observed the sampling of various environmental media as specified in the ODCM and
      reviewed any anomalous environmental sampling events including assessment of any
      positive radioactivity results. The inspectors reviewed any changes to the ODCM. The
      inspectors verified the operability and calibration of the meteorological tower instruments
      and meteorological data readouts. The inspectors reviewed environmental sample
      laboratory analysis results, laboratory instrument measurement detection sensitivities,
      laboratory quality control program audit results, and the inter- and intra-laboratory
      comparison program results. The inspectors reviewed the groundwater monitoring
      program as it applies to selected potential leaking structures, systems, or components;
      and 10 CFR 50.75(g) records of leaks, spills, and remediation since the previous
      inspection.
      Groundwater Protection Initiative Implementation
      The inspectors reviewed: groundwater monitoring results; changes to the Groundwater
      Protection Initiative (GPI) program since the last inspection; anomalous results or
      missed groundwater samples; leakage or spill events including entries made into the
      decommissioning files (10 CFR 50.75 (g)); evaluations of surface water discharges; and
                                              29
      PSEGs evaluation of any positive groundwater sample results including appropriate
      stakeholder notifications and effluent reporting requirements.
      Identification and Resolution of Problems (1 sample)
      The inspectors evaluated whether problems associated with the REMP were identified at
      an appropriate threshold and properly addressed in PSEGs CAP.
  b. Findings
      No findings were identified.
4.    OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
      Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with
      Complications (6 samples)
  a. Inspection Scope
      The inspectors reviewed PSEG submittals for the following Initiating Events Cornerstone
      PIs for the period of July 1, 2015 through June 30, 2016.
        Unit 1 & 2 Unplanned Scrams
        Unit 1 & 2 Unplanned Power Changes
        Unit 1 & 2 Unplanned Scrams with Complications
      To determine the accuracy of the PI data reported during those periods, inspectors used
      definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02,
      Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors
      reviewed PSEG operator narrative logs, maintenance planning schedules, condition
      reports, event reports, and NRC integrated IRs to validate the accuracy of the
      submittals.
  b. Findings
      No findings were identified.
4OA2 Problem Identification and Resolution (71152 - 4 samples)
.1    Routine Review of Problem Identification and Resolution Activities
  a. Inspection Scope
      As required by Inspection Procedure 71152, Problem Identification and Resolution, the
      inspectors routinely reviewed issues during baseline inspection activities and plant
      status reviews to verify PSEG entered issues into their CAP at an appropriate threshold,
      gave adequate attention to timely corrective actions, and identified and addressed
      adverse trends. In order to assist with the identification of repetitive equipment failures
      and specific human performance issues for follow-up, the inspectors performed a daily
                                                  30
      screening of items entered into their CAP and periodically attended condition report
      screening meetings. The inspectors also confirmed, on a sampling basis, that, as
      applicable, for identified defects and non-conformances, PSEG performed an evaluation
      in accordance with 10 CFR Part 21.
  b. Findings
      No findings were identified.
.2    Semi-Annual Trend Review
  a. Inspection Scope
      The inspectors performed a semi-annual review of site issues to identify trends that
      might indicate the existence of more significant safety concerns. As part of this review,
      the inspectors included repetitive or closely-related issues documented by PSEG in the
      CAP and repetitive or closely-related issues that may have been documented by PSEG
      outside of the CAP, such as trend reports, PIs, major equipment problem lists, system
      health reports, MR assessments, and maintenance or CAP backlogs. The inspectors
      also reviewed PSEG CAP database for the first and second quarters of 2016 to assess
      notifications written in various subject areas (equipment problems, human performance
      issues, etc.), as well as individual issues identified during the inspectors daily condition
      report review (Section 4OA2.1). The inspectors reviewed the PSEG CAP trending data,
      conducted under LS-AA-125, to verify that PSEG personnel were appropriately
      evaluating and trending adverse conditions in accordance with applicable procedures.
  a. Findings and Observations
      No findings were identified.
      Equipment Reliability (Steady)
      The inspectors documented an adverse trend in either equipment reliability or unplanned
      entries into TS shutdown limiting conditions for operation (LCO) in each of the previous
      four semi-annual trend review periods (IRs 05000272; 311/2014003, 2014005, 2015002
      and 2015004). In February 2016, in response to PSEGs unplanned LCO performance
      goal not being met, PSEG performed Common Cause Evaluation (CCE) 70184208,
      Unplanned Shutdown LCO Goal Not Met. The CCE was completed in April of 2016, with
      the following results:
              A trend of data over an 18-month period from August 2014 through January 2016
              identified 68 unplanned shutdown LCOs, which far exceeded the station goal of
              no more than 8 in a 12-month rolling average. PSEGs CCE concluded:
              1) 15 LCO entries were attributed to faulty parts; 2) 10 entries were attributed to
              equipment not being repaired in a timely manner; and 3) more follow up
              evaluations were warranted:
                  o    Work Group Evaluation (WGE) 70185245, Follow up Evaluation from
                        Unplanned shutdown LCOs, was performed to further evaluate the
                        10 entries attributed to equipment not being repaired in a timely manner.
                        PSEG attributed the cause to ineffective development and
                                        31
                implementation of equipment reliability strategies to ensure reliability until
                long-term elimination or mitigating actions were in place. Actions were
                assigned to develop bridging strategies for Plant Health Committee items
                and rollout to Station Oversight Committee (SOC) and Management
                Review Committee (MRC) an expectation that if an unplanned LCO
                occurs, a causal evaluation should be performed.
The inspectors noted some improvement in the area of unplanned entries into TS LCOs
in recent months; specifically, 44 unplanned shutdown LCOs occurred from June 2015
to April 2016, but only seven occurred in the last 3 months of this 10 month period. The
inspectors determined that the adverse trend of equipment failures did not constitute a
performance deficiency, because the trend, by itself, did not constitute a violation of any
NRC requirement. The inspectors inspected individual equipment failures as ROP
baseline inspection samples documented in other sections of this report.
Main Control Room Deficiencies (Steady with recent improvement)
The inspectors noted an adverse trend in main control room deficiencies, as evident by a
Red station performance metric dating back to mid-2015, when the station metric was
redefined to align with the current industry metric. Specifically, in June of 2016, Unit 1
had 69 and Unit 2 had 45, versus a red performance metric threshold of 16 or more.
However, the inspectors noted recent improvements in this area. Specifically, Unit 1
reduced the backlog from 99 in January 2016 to 69 in June, and Unit 2 reduced the
backlog from 73 before the fall 2015 refueling outage to 45 in June 2016.
Untimely Reportability Determinations (Steady)
In Section 4OA2.2 of IR 2015-004, the inspectors identified that past operability
determinations were untimely in supporting conclusions of LER reportability in 60 days,
and listed multiple examples. In response to a LER 05000311/2016-001-000 being
submitted well beyond 60 days from the occurrence of the event (see Sections 4OA2.3
and 4OA7 of this report), PSEG performed a review under apparent cause evaluation
(ACE) 70183590, to determine the extent of condition relative to missed or late reports
under 10 CFR 50.72 and 50.73. PSEG concluded the following: 1) The execution of
CAP does not support timely completion of evaluation products to support 60-day LER
submittals; 2) SOC and MRC have a low threshold for requesting reportability reviews;
and 3) Salem has a high number of supplemental LERs relative to the industry (four in
2015 versus an industry average of less than one), indicating that CAP does not support
timely cause evaluation completion, which require LERs to be supplemented. The
inspectors noted that PSEGs conclusion 3 above is consistent with a previously
identified trend by the inspectors documented in Section 4OA2.2 of IR 2015002, which
listed a steady increase in CAP evaluation products and subsequent trend of CAP
products falling behind station timeliness goals. As a result of the ACE listed above,
PSEG issued a temporary standing order to develop interim guidance until process
improvements and controls were institutionalized for reportability, assigned corrective
actions to develop procedure improvements and controls for accompanying reportability
reviews, and to develop the appropriate change management plan for process changes
to perform reportability reviews. The inspectors did not identify any actual violations of
10 CFR 50.72 or 50.73 during the performance of this inspection. The timeliness of
reportability determinations remains a minor adverse trend.
                                                32
      Status Control and Human Performance Events (Improving)
      The inspectors previously documented an adverse trend in status control in Section
      4OA2.5 of IR 2014005. In December of 2015, Nuclear Oversight identified an adverse
      trend in status control. In February of 2016, PSEG completed a CCE in response to the
      adverse trend in plant status control. Additionally, status control was a focus area for the
      station in 2016. Since that time, the inspectors noted considerable improvement in the
      area of status control. Specifically, as of June 1, 2016, the station achieved 181 status
      control event free days. However, in recent months, the inspectors noted several human
      performance events that were not classified as status control events, though they reflect
      many of the same behavioral breakdowns in standards and fundamentals. Examples
      include:
              April 17: 1B EDG invalid actuation: During the performance of solid state
              protection system testing in Mode 6 (refueling), the 1B EDG unexpectedly started
              while an operator in the field was attempting to replace a light bulb on the test
              box. PSEG performed an investigation and determined that the most likely
              cause was due to the operators finger bumping the block switch during the bulb
              replacement, which was enough pressure to allow the test block signal to be
              momentarily interrupted. PSEG reported this event as a telephone notification
              under 10 CFR 50.73(a)(1) and (a)(2)(iv)(A) on June 15.
              April 25: #1 Emergency Compressed Air Compressor trip during leak test -
              PSEG performed Quick Human Performance Investigation (QHPI) 70186240 and
              determined the operator in the control room did not understand the report from
              the equipment operator in the field, and determined that three-way
              communication was not used when it should have been.
              April 19: 22B circulator bypass valve operated in the wrong direction - PSEG
              performed QHPI 71085972 and determined that an equipment operator did not
              fully open the 22B circulator outlet valve prior to attempting remote closure of the
              22B circulator bypass, which resulted in the bypass valve failing to stroke closed.
              March 27: Station Blackout (SBO) air compressor tripped - the equipment
              operator did not follow procedure while testing the SBO air compressor, resulting
              in a trip of the compressor (20723821).
      The inspectors determined that none of the issues above were of more than minor
      significance, because none of them resulted in a significant plant transient or loss of a
      mitigating system. The inspectors determined that although the trend in events
      classified as status control had improved, the behaviors that contributed to them were
      still present.
.3    Annual Sample: Unit 2 Auxiliary Feedwater Loop Response Time Exceeded Technical
      Specifications
  a. Inspection Scope
      The inspectors performed an in-depth review of PSEGs identification, evaluation, and
      resolution following the discovery that a channel of the 21 AFW pump engineered
      safety feature actuation system (ESFAS) automatic actuation logic was inoperable.
                                            33
  On November 18, 2015, maintenance personnel compiling test data, collected on
  October 18, 2015, during the Unit 2 plant shutdown for the fall 2015 refueling outage,
  determined that the pump instrumentation loop time response exceeded test acceptance
  criteria. At the time, Unit 2 was shut down in a refueling outage and AFW was not
  required. The cause of the slow loop response was due to the isolation valve to the
  21 AFW pump discharge pressure transmitter (2PA3450) being closed. The pressure
  transmitter provided input into the pump run-out protection and flow control circuit.
  The closed isolation valve caused the pressure transmitter to take longer to sense pump
  discharge pressure, which resulted in the slow opening of the pump SG flow control
  valves (valves 23AF21 and 24AF21). PSEGs investigation determined that the
  condition likely existed since April 20, 2015, following the completion of maintenance on
  the pressure transmitter. On January 19, 2016, PSEG determined that the condition
  was reportable to the NRC. PSEG initiated an ACE to determine the cause of the
  untimely review and evaluation of the surveillance data collected on October 18, 2015,
  and a WGE to determine the cause of the improperly positioned isolation valve to
  pressure transmitter 2PA3450. The inspectors performed an in-depth review of the ACE
  and WGE and corrective actions associated with the issues documented in Orders
  70183590 and 70182519. PSEG submitted Licensee Event Report (LER)
  05000311/2016-001-000, AFW Loop Response Time Exceeded TSs, on March 21,
  2016, as an operation or condition which was prohibited by the plants TS. The
  inspectors review of the LER is documented in Section 4OA3.1 of this report. Section
  4OA7 documents the enforcement aspects related to the LER.
  The inspectors assessed PSEGs problem identification threshold, causal analysis,
  extent of condition reviews, compensatory actions, and the prioritization and timeliness
  of corrective actions to determine whether PSEG was appropriately identifying,
  characterizing, and correcting problems associated with these issues and whether the
  planned or completed corrective actions were appropriate. The inspectors compared
  the actions taken to the requirements of PSEGs CAP and 10 CFR Part 50, Appendix B.
  In addition, the inspectors reviewed documentation associated with this issue, and
  interviewed engineering and maintenance personnel to assess the effectiveness of
  the implemented and planned corrective actions.
b. Findings and Observations
  No findings were identified.
  Maintenance personnel compiling 21 AFW pump loop time response test data identified
  the slow response times for valves 23AF21 and 24AF21, and entered this issue into the
  CAP as NOTF 20710947. During their review, PSEG identified that the instrument
  isolation valve for the 21 AFW pump discharge pressure transmitter (2PA3450) was
  closed versus the required position of open. The improperly positioned valve was
  promptly placed into the required open position. PSEG entered the improperly
  positioned valve into the CAP as NOTF 20709417, and performed a prompt investigation
  and a WGE. The inspectors determined that action taken by PSEG upon discovery of
  the slow response times for valves 23AF21 and 24AF21 were prompt and appropriate.
  The inspectors reviewed Order 70182519, which documented the WGE for instrument
  isolation valve for 2PA3450 being found in the incorrect position. Although the actual
  cause of the improperly positioned isolation valve was indeterminate, PSEG concluded
  that the condition most likely existed since April 20, 2015, when maintenance was last
                                          34
performed on 2PA3450. Corrective actions included plans to install human factors tools
(i.e., additional measure devices) on all transmitter isolation valves located in both the
Unit 1 and 2 AFW instrumentation panels. The inspectors concluded that PSEGs
planned corrective action was appropriate.
The inspectors reviewed the timeline of events from the collection of test data on
October 18, 2015, until the submittal of the LER for the condition prohibited by TS
related to the slow instrument loop response time for the 21 AFW pump. The inspectors
concluded that information was available to PSEG personnel on November 20, 2015,
that the condition was potentially reportable when the cause was determined to be due
to the incorrectly positioned instrument isolation valve to 2PA3450. However, the
required LER was not submitted until March 21, 2016.
The inspectors reviewed PSEGs investigation into the reportability timeliness issue, as
documented in Order 70183590. PSEG determined that the cause was due to work
tracking assignments not being made to facilitate identification and completion of the
required past operability review in accordance with Engineering standard practice. The
normal practice to evaluate issues for potential past operability/reportability is for the
SOC to assign a technical evaluation to Engineering to review. In this case an action
item was assigned to Engineering versus a technical evaluation. The due dates for
action items are allowed to be extended by the assignee whereas, the process of
extending technical evaluations has more stringent controls. Therefore, the priority of
the action item was not established at the correct threshold by the assigned
engineering supervisor. This resulted in extensions of the due date for the past
operability/reportability review. PSEGs corrective actions taken or planned included
issuance of an Operations standing order, which provided additional interim guidance for
performing past operability and reportability reviews, and to develop process
improvements and controls for accomplishing past operability and reportability reviews.
The inspectors concluded that the actions taken or planned appeared to appropriately
address the reportability timeliness issue. In accordance with IMC 0612, "Power
Reactor Inspection Reports," the above timeliness of reportability issue constituted a
violation of minor significance that is not subject to enforcement action in accordance
with the Enforcement Policy.
As discussed in Order 70183590, PSEG recognized that the SOC inappropriately
assigned an action item versus the more appropriate technical evaluation to
Engineering for the past operability/reportability review. The inspectors observed that
actions taken by PSEG did not directly address the shortfall of the SOC in this case.
The inspectors noted that there was a low level assignment for the SOC to evaluate for a
human performance crew clock reset; however, the clock reset was determined to not be
necessary. The inspectors noted that the other actions taken or planned discussed
above appeared to be adequate to address the inappropriate extensions of past
operability and reportability reviews.
In NRC Inspection Report 05000272, 05000311/2015004, dated February 10, 2016, a
problem identification and resolution adverse trend was documented related to past
operability determinations being untimely in supporting conclusions of LER reportability
within sixty days. The inspectors concluded that the untimely past operability and
reportability review of the failed 21 AFW pump instrument loop time response test as an
additional example of the adverse trend identified in NRC IR 05000272,
                                                35
      05000311/2015004 and updated in Section 4OA2.2 of this report. At the end of this
      inspection period, PSEG had not entered this adverse trend into their CAP.
.4    Annual Sample: Struthers-Dunn Relay Failures in Safety-Related Applications
  a. Inspection Scope
      The inspectors performed an in-depth review of PSEGs ACE and corrective actions
      associated with NOTF 20681569 related to a 21 containment spray (CS) pump failure to
      start. The 21 CS pump failed to start on October 2, 2015, during post-maintenance
      testing following scheduled maintenance. The 21 CS pump failure to start was
      investigated by PSEG during subsequent troubleshooting. Additionally, a failure modes
      and causal table determined the most likely cause for the failure to start was from a
      starting relay high contact resistance. PSEG postulated that contact contamination
      created a high resistance condition that was subsequently cleared due to the wiping
      action of the relay contact. The starting relay was a Struthers-Dunn Model 219BBX-240
      and was replaced. The failed relay was sent for failure analysis to an offsite laboratory.
      The lab was unable to repeat the high resistance contact operation that was observed at
      Salem. The lab functional testing did not yield any deficiencies or failure mechanisms.
      The inspectors assessed PSEGs problem identification threshold, causal analyses,
      technical analyses, extent of condition reviews, and the prioritization and timeliness of
      corrective actions to determine whether PSEG was appropriately identifying,
      characterizing, and correcting problems associated with this issue. The inspectors
      reviewed the circumstances of this relay failure issue to ascertain the appropriateness of
      corrective actions. The inspectors also assessed PSEGs corrective actions to prevent
      recurrence. The inspectors compared the actions taken to the requirements of PSEGs
      CAP and 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action. In addition, the
      inspectors reviewed documentation associated with this issue, including condition
      reports, and interviewed engineering personnel to assess the effectiveness of the
      planned and implemented corrective actions.
  b. Findings and Observations
      No findings were identified.
      The Struthers-Dunn relays in critical applications were all replaced in 1996 and 1997
      during extended unit shutdowns. From about 2000 to 2015, Salem experienced
      Struthers-Dunn relay failures in critical applications at about one MR functional failure
      per year. In May 2013, after a Struthers-Dunn relay failure associated with the
      15 containment fan cooling unit (CFCU), PSEG developed extensive corrective actions
      to revise preventive maintenance (PM) templates and determine an appropriate
      replacement periodicity. An accelerated testing program was a corrective action and
      completed in March 2014 to determine the number of relay operations when the contacts
      gold flashing began to wear away exposing the silver base. Exposing the silver contact
      base leads to a corrosion condition called sulfidation creating a high resistance between
      relay contacts. Offsite laboratory analysis of previous Struthers-Dunn relays had
      identified worn gold flashing and sulfidation.
      PSEG determined from the accelerated relay testing program that Struthers-Dunn relays
      in CFCU applications should be replaced every 10 years. The CFCUs have more
                                                36
      frequent equipment on/off cycles compared to other critical Struthers-Dunn applications.
      PSEG determined all other Struthers-Dunn relay replacements should be replaced at
      20 years. PSEG established the 20 year replacement interval based on 400 relay
      operations for the equipment considered. However, the inspectors noted that for some
      relay applications, major gold flashing wear or wiping resulting in areas of exposed silver
      was observed from the accelerated failure testing results at just 350 relay operations.
      PSEG generated notification 20734284 in response to the inspectors observation for
      resolution and to reevaluate the intended 20 year replacement periodicity.
      The corrective action due dates for the final PM templates are due in August 2016.
      PSEG accelerated and completed the Struthers-Dunn relay replacements in all CFCU
      applications. The inspectors noted that if PSEG finalizes a 20 year replacement for
      non-CFCU applications, considering that all Struthers-Dunn relays were replaced in
      1996 to 1997, then all Struthers-Dunn relays would now or in the near term require
      replacement. PSEG initiated notification 20734280 in response to the inspectors
      observation for resolution.
.5    Annual Sample: Unexpected Number of Degraded Baffle-Former Bolts Discovered in
      the Unit 1 Reactor Pressure Vessel
  a. Inspection Scope
      The inspectors performed an in-depth review of PSEGs technical evaluation and
      corrective actions associated with NOTF 20726264 for baffle-former (baffle) bolts found
      with indications of degradation during the spring 2016 Salem Unit 1 24th refueling outage
      (1R24). PSEG performed ultrasonic examinations of the baffle bolts in accordance with
      their procedures in response to recent industry operating experience and 1R24 visual
      examination results indicating 18 visually damaged baffle bolts. After an unexpected
      number of degraded baffle bolts were discovered, PSEG staff entered the issue into their
      corrective action program as NOTF 20727538 and reported the issue to the NRC as
      Event Notification No. 51902 on May 3, 2016, because the as-found number and
      location of degraded bolts, which were mainly concentrated in three of the eight baffle
      assemblies, represented an unanalyzed condition. PSEG staff completed corrective
      actions to replace 189 of 192 potentially degraded baffle bolts on Unit 1. As
      documented in Section 1R18, PSEG did not remove and replace three bolts that were
      potentially degraded due to difficulties encountered during the removal/replacement
      process.
      The baffle bolts help secure vertical plates (also referred to as baffle plates) inside the
      reactor vessel, which then forms a structure surrounding the reactor fuel assemblies to
      orient the fuel and to direct coolant flow through the core. A sufficient number of baffle
      bolts are required to remain intact to secure the baffle plates in place so as to not affect
      control rod insertion or impede emergency core cooling flow during postulated accident
      conditions. Bolt heads that separate and are no longer held in place by bolt lock-tabs
      can also become a loose parts concern.
      The inspectors assessed whether PSEG acceptable baffle bolt pattern analysis for
      Unit 1 was completed in accordance with the NRC-approved methodology and provided
      appropriate structural margin for the next cycle of operation to ensure the Unit 1 baffle
      plates will remain in place during both normal operation and limiting postulated accident
      conditions. The inspectors also assessed whether PSEGs evaluations of the baffle
                                              37
  bolts installed in Salem Unit 2 were technically sufficient to conclude the Unit 2 baffle
  assembly will perform as intended until the next planned refueling outage, at which time
  PSEG plans to examine the bolts. The inspectors reviewed PSEGs procedures for
  determining the functionality and operability of degraded systems, components and
  structures as they relate to Unit 2. Additionally, the inspectors interviewed PSEG
  engineering personnel and contractor staff to discuss the results of PSEGs technical
  evaluations and to assess the effectiveness of the implemented and planned corrective
  actions.
  The inspectors assessed PSEGs problem identification threshold, cause analyses,
  extent of condition, compensatory actions, and the prioritization and timeliness of
  PSEGs corrective actions to determine whether PSEG staff were properly identifying,
  characterizing, and correcting problems associated with this issue and whether the
  planned or completed corrective actions were appropriate. The inspectors compared the
  actions taken to PSEGs corrective action program, operability determination process,
  and the requirements of 10 CFR Part 50, Appendix B. The inspectors observed portions
  of baffle bolt replacement activities at Unit 1 and reviewed the final visual examination of
  the baffle bolts and plates once the work was completed.
b. Observations
  The NRC responded to the initial discovery of an unexpected number of baffle bolts
  found degraded at Salem Unit 1 by implementing a comprehensive inspection plan
  consisting of various baseline inspection samples to assess the extent of the issue and
  to determine the necessary NRC actions. A previously planned ISI sample (Refer to
  Section 1R08) was expanded to include a review of the capability of the NDE techniques
  for ultrasonically testing (UT) the baffle bolts, to evaluate the UT results, and to observe
  a portion of bolt replacement activities on-site. Two permanent modification samples
  (Refer to Section 1R18) were conducted to review the design change package and
  evaluations associated with the new, replacement baffle bolts, and to review the PSEG
  design change package documenting the as-left baffle bolting pattern in Unit 1. NRC
  resident inspectors reviewed PSEGs foreign material controls and loose parts analysis
  (Refer to Section 1R20) to address the potential for missing bolt heads and concluded it
  would not impact safe operation of the plant.
  NRC Region I based inspectors, accompanied by an expert from the NRC Office of
  Nuclear Reactor Regulation, completed this annual problem identification and resolution
  inspection sample, to verify that PSEGs evaluations and corrective action to replace
  Unit 1 baffle bolts were completed in accordance with NRC approved methodology to
  support a conclusion that the Unit 1 baffle assembly meets the plant design basis. The
  inspectors also reviewed the adequacy of PSEGs technical evaluations completed to
  determine whether there is a reasonable expectation the Unit 2 baffle assembly will
  perform as intended during the current operating cycle. The results of this review are
  discussed herein and in Section 1R15 of this report.
  At the completion of this inspection, PSEGs conduct of a RCE to determine the causes
  of the failure of the baffle bolts in Unit 1 was ongoing. The inspectors determined
  PSEGs RCE will not be completed until after laboratory tests and analyses, planned for
  fall 2016, are performed on a sample of the bolts removed from Unit 1. PSEGs
  technical evaluation discussed the cause of the degraded baffle bolts as primarily due to
  IASCC. This determination was based on industry operating experience related to baffle
                                          38
bolt failure in both foreign and domestic plants, is a known degradation mechanism and
the operational and physical characteristics of both Salem plants indicate that they are
susceptible to this mechanism. The inspectors reviewed PSEGs technical evaluation
and the supporting operating experience related to baffle bolt failures at other plants.
IASCC is a cracking mechanism that occurs over a long period of time when susceptible
metals are exposed to neutron radiation from the reactor core and stresses as part of
normal design and operation. The inspectors determined PSEG identified the likely
cause of the baffle bolt degradation and their plans to complete a RCE when additional
metallurgical information was available was appropriate.
Following identification of the degraded baffle bolts on Unit 1, PSEGs immediate
corrective action was to analyze the as-found condition and begin replacing bolts that
either had visual indications of bolt failure (protruding bolt head for example), did not
pass UT examination, or were not accessible for UT examination. The as-found number
and pattern of these bolts exceeded the acceptance criteria in the plants analysis that
was prepared in advance of the baffle bolt examinations; therefore, PSEG reported this
discovery to the NRC as an unanalyzed condition in Event Notification 51902 on May 3,
2016. PSEG staff completed corrective actions to replace 189 of 192 potentially
degraded baffle bolts. PSEG did not remove and replace three bolts that were
potentially degraded due to difficulties encountered during the removal/replacement
process. As previously documented in Section 1R18, one bolt had an indication during
ultrasonic testing but was not visibly damaged. The second bolt was inaccessible for
ultrasonic testing, which would have required replacement. The third bolt had
successfully passed an ultrasonic test but had a visual indication on one of the lock bar
welds which may have indicated a crack in the weld.
The inspectors determined that PSEG staff performed an acceptable bolt pattern
analysis that evaluated the replacement bolt pattern for Unit 1. The inspectors found
the results of the analysis accounted for a conservative failure rate of bolts and provided
appropriate margin for one cycle of operation. The inspectors verified that PSEGs
methodology for its acceptable bolt pattern analyses, including its determination of
margin, was consistent with the NRC-approved methodology in topical report
WCAP-15029-NP-A (ML15222A882). The inspectors determined that PSEG staff
tracked corrective actions to re-examine the Unit 1 baffle bolts during the next planned
refueling outage. The inspectors noted the new baffle bolts were made of a material
(316 SS) with improved resistance to IASCC and included an improved design to reduce
the stresses at the head to shank transition, both of which are enhancements compared
to the original bolts.
As part of an extent of condition assessment, PSEG entered NOTF 20727590 in its
corrective action program to evaluate the potential for degraded baffle bolts on Unit 2.
PSEG operators performed an IOD and concluded that the baffle assembly was
operable. PSEG staff performed a subsequent technical evaluation that concluded
Unit 2 would experience less baffle bolt degradation than Unit 1 based on several plant
factors. The inspectors reviewed PSEGs technical evaluations, including the inputs for
the operability determination, and noted that PSEG staff concluded there was not a
degraded condition at Unit 2. In consideration of the guidance in PSEGs operability
procedure and operating experience from Unit 1 and other plants, the NRC issued an
NCV in this report because PSEG did not perform an OPEval for Unit 2 as a follow-up to
the IOD for the potential impact on supported systems controlled by the Technical
Specifications (Refer to Section 1R15).
                                                39
      As a corrective action, PSEG staff performed OpEval 2016-015 and demonstrated that
      the Unit 2 baffle assembly remained operable. The inspectors concluded that this
      supplemental evaluation provided adequate technical justification for the continued
      operation of Unit 2 until the next refueling outage in spring 2017, at which time PSEG
      plans to examine the baffle bolts. PSEG also implemented compensatory measures to
      monitor the reactor coolant system for any signs of fuel leakage, which could be an
      indicator of baffle bolt failures and to generate additional contingency actions in
      response to indications of increased unidentified leakage or receipt of a metal impact
      monitoring system alarm.
      The inspectors reviewed Westinghouse Nuclear Safety Advisory Letter NSAL-16-1,
      which discussed the results of recent baffle bolt inspections and provided
      Westinghouses recommendations on this issue. The letter described the plants as most
      susceptible (i.e. Tier 1a) to this degradation as Westinghouse 4-loop reactors limited to
      those with a down-flow configuration and using Type 347 stainless steel. A non-
      proprietary presentation on the contents of NSAL-16-1 can be found at ML16202A063.
      The inspectors noted the recommendation was to complete UT volumetric examination
      of the baffle bolts at the next scheduled refueling outage, and that PSEG had already
      planned this action for Unit 2. The inspectors determined PSEGs overall response to
      the issue was commensurate with the safety significance, was timely, and included
      appropriate compensatory actions. The inspectors concluded that the actions completed
      and planned were reasonable to address the ongoing aging management of baffle bolts.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153 - 4 samples)
.1    Plant Events (2 samples)
  a. Inspection Scope
      For the plant events listed below, the inspectors reviewed and/or observed plant
      parameters, reviewed personnel performance, and evaluated performance of mitigating
      systems. The inspectors communicated the plant events to appropriate regional
      personnel, and compared the event details with criteria contained in IMC 0309, Reactive
      Inspection Decision Basis for Reactors, for consideration of potential reactive inspection
      activities. As applicable, the inspectors verified that PSEG made appropriate emergency
      classification assessments and properly reported the event in accordance with 10 CFR
      50.72 and 50.73. The inspectors reviewed PSEGs follow-up actions related to the
      events to assure that PSEG implemented appropriate corrective actions commensurate
      with their safety significance.
        Unit 1, Baffle to former bolts found broken or degraded on May 3 (EN 51902)
        Unit 2, Reactor trip from main turbine trip on June 28 (EN 52048)
  b. Findings
      No findings were identified.
                                                40
.2    (Closed) LER 05000311/2016-001-000: Auxiliary Feedwater Loop Response Time
      Exceeded Technical Specifications
  a. Inspection Scope
      While evaluating surveillance instrumentation loop time response test data associated
      with the 21 AFW pump that was collected during the Unit 2 plant shutdown for the fall
      2015 refueling outage, PSEG determined that a channel of the pumps ESFAS
      automatic actuation logic was inoperable. In November 2015, PSEG personnel
      identified the slow loop response time during surveillance testing. The cause of the slow
      loop response was due to the isolation valve to the 21 AFW pump discharge pressure
      transmitter (2PA3450) being closed. The pressure transmitter provided input into the
      pump run-out protection and flow control circuit. The closed isolation valve caused the
      pressure transmitter to take longer to sense pump discharge pressure which resulted in
      slow opening of the pump steam generator flow control valves (valves 23AF21 and
      24AF21). PSEGs investigation determined that the condition existed since April 20,
      2015, following the completion of maintenance on the pressure transmitter. An
      engineering review concluded that, although the AFW loop response time test results did
      not satisfy TS requirements, the accident analysis assumptions remained valid and the
      condition did not result in an unanalyzed condition. This issue is discussed in more
      detail in Section 4OA2.1 of this report. No other issues were identified during the review
      of the LER. This LER is closed.
  b. Findings
      The enforcement aspects of this violation are discussed in Section 4OA7.
.3    (Closed) LER 05000311/2016-002-00: Automatic Reactor Trip Due to Main Turbine Trip
  a. Inspection Scope
      On February 4, Salem Unit 2 automatically tripped from approximately 74 percent 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 AVR volts/hertz over excitation protection
      relay. All emergency core cooling systems and emergency safeguards feature systems
      functioned as expected. PSEG submitted this LER in accordance with 10 CFR 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)," specifically automatic actuation of
      the Reactor Protection System and the Auxiliary Feedwater System for this event. The
      inspectors reviewed the LER, the associated cause evaluation, and interviewed PSEG
      staff. This LER is closed.
  b. Findings
      Introduction. A Green, self-revealing FIN was identified against MA-AA-716-010,
      Maintenance Planning Process, Revision 18, when PSEG WOs did not specify the
      appropriate procedure to perform satisfactory modification testing of the main generator
      AVR protective relay (model STV1). Consequently, the relay actuated below its design
      setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main turbine and
      reactor.
                                        41
Description. On February 4, 2016, Unit 2 experienced an automatic main turbine and
reactor trip from approximately 74 percent power, initiated by a trip of the main generator
AVR STV 1 relay. The STV1 is designed to protect the main generator, main power
transformers, and auxiliary transformer from over-excitation due to over-voltage
operation, and consists of an adjustable pickup dial setting between 1.8 and
2.5 voltz/hertz (V/Hz), ranging from 108 - 150 V at 60 Hz. PSEG design calculation
ES-7.007, Salem Unit 2 Generator and Transformer Protective Relay Setpoint
Determination, Revision 5, established a design setpoint for the STV1 relay of 138 V at
60 Hz, corresponding to a V/Hz dial setting of 2.3, with an associated time delay of
45 seconds. Just prior to the Unit 2 trip on February 4, the main generator was
operating at approximately 26.1 kV following a manual MVAR adjustment, which
corresponded to 2.175 V/Hz sensed at the STV1. After the Unit 2 trip, PSEG
troubleshooting determined the as-found pick-up value of the STV1 was 2.17 V/Hz. The
post-trip sequence-of-event data showed the STV1 time delay unit picked up 45 seconds
after exceeding 2.17 V/Hz, which tripped the AVR and resulted in a loss of field to the
main generator, thereby causing a turbine trip and coincident reactor trip.
In response to the Unit 2 reactor trip, PSEG performed RCE 70183932, Unit 2
Automatic Reactor Trip on Generator Protection, to determine why the STV1 relay
actuated below the design setpoint. PSEG identified two root causes: 1) setpoint drift
due to a damaged rheostat; and 2) the damaged rheostat was not identified due to an
inadequately planned work order that specified a less than adequate post-modification
test method. PSEG DCP 80109718, Salem Unit 2 AVR Replacement, supplement 10,
documented that a modification test was required for the STV1 relay in accordance
with Relay Department test procedures, which subsequently required the use of an
engineering-approved Relay Test Order (RTO). However, Maintenance Planning
prepared WO 60122561-0014 to perform STV1 modification testing without specifying
the applicable test procedures. MA-AA-716-010, step 4.5.7, states If approved
procedure(s) are available which cover all or part of the work scope, then specify in the
work package to perform work in accordance with the procedure(s). Additionally, step
3.1.1 states, in part, Maintenance Planners are responsible to interface with: System
Engineers for providing supplemental technical direction on a case by case basis as
needed; and Maintenance Shops to obtain information needed to produce an
adequately detailed work package.
Additionally, the RCE determined that WO 60122561-0014 directed the PSEG LTS
department to perform modification testing of the STV1 relay. However, LTS utilized
different testing procedures than the Relay department procedures specified in the DCP.
The LTS modification testing performed on October 5, 2015, did not functionally test the
STV1 relay at its design setpoint of 138 volts at 60 Hz, which corresponded to a dial
setting of 2.3 as discussed above. The RCE determined the manufacturer-specified
acceptance testing required verifying the V/Hz pick-up was within one percent of all V/Hz
adjustable dial settings, whereas the LTS procedure required the V/Hz pickup at a four
percent tolerance on the 2.0 dial setting, or four percent of 120 volts at 60 Hz. The
STV1 relay pickup value from the LTS testing on October 5, 2015, fell outside of the one
percent tolerance specified by the manufacturer, and LTS did not have a technical basis
to support an allowable tolerance of four percent. The RCE determined that returning
the relay to the manufacturer-specified setting of one percent would have required
adjusting the damaged rheostat to a position where the relay would not have functioned,
and therefore would have resulted in a failed acceptance test that would have prevented
                                            42
the relay from being installed in the plant. The inspectors verified that the STV1 RTO
specified a one percent tolerance at the design setpoint of 138 volts at 60 Hz.
Analysis. The inspectors determined that a performance deficiency existed because
PSEG WOs did not specify the appropriate procedure to perform satisfactory
modification testing of the main generator AVR protection relay STV1. This issue was
more than minor since it was associated with the procedure quality attribute of the
Initiating Events cornerstone and adversely impacted its objective to limit the likelihood
of events that upset plant stability (main generator and turbine trip) and challenge critical
safety functions. Specifically, due to a work order that was not planned properly, PSEG
did not test the STV1 relay at the applicable design setpoint and manufacture-specified
tolerance. Consequently, the relay actuated below its design setpoint on February 4,
2016, resulting in an automatic trip of the Unit 2 main turbine and reactor. Using IMC
0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this
finding was of very low safety significance, or Green, since mitigating equipment relied
up to transition the plant to stable shutdown remained available.
The finding had a cross-cutting aspect in the area of Human Performance, Work
Management, in that the organization implements a work process that includes the need
for coordination with different groups or job activities. Specifically, the PSEG process for
planning the STV1 relay modification test WO included the need for maintenance
planners to coordinate with engineering to provide design setpoint and tolerance
specifications, as well as electrical maintenance departments to verify appropriate test
procedures were specified in the WO. The inspectors determined that PSEG did not
adequately implement the work process in accordance with MA-AA-716-010. [H.5]
Enforcement. MA-AA-716-010, Maintenance Planning Process, Revision 18, step 4.5.7,
states If approved procedure(s) are available which cover all or part of the work scope,
then specify in the WO to perform work in accordance with the procedure(s). Contrary
to the above, PSEG did not specify in the WO to perform work in accordance with
approved Relay department test procedures, and the associated RTO, for modification
testing of the STV1 relay on October 5, 2015. Specifically, due to a work order that was
not planned properly, PSEG did not test the STV1 relay at the applicable design setpoint
and manufacturer-specified tolerance. Consequently, the relay actuated below its
design setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main
turbine and reactor. PSEG entered the issue in CAP as notification 20717849 and
performed RCE 70183932. Planned corrective actions included replacing the failed
STV1 relay with a properly tested STV1 relay, verifying other STV relays were
appropriately tested as an extent of condition, and revising LTS department relay test
procedures to ensure all applicable acceptance criteria are incorporated. This finding
does not involve enforcement action because no violation of a regulatory requirement
was identified. Because this finding does not involve a violation and is of very low safety
significance, it is identified as a Finding. (FIN 05000311/2016002-03, Inadequate Work
Order Planning Results in Main Generator AVR STV Relay Trip)
                                              43
4OA5 Other Activities
.1    (Closed) URI 05000272; 311/2015008-01: Inadequate Maintenance Rule System
      Performance Criteria (PC) Selection
  a. Inspection Scope
      In IR 05000272; 311/2015-008, inspectors identified a URI associated with inadequate
      Maintenance Rule Performance Criteria selection.
      During this review the inspectors noted approximately 25 high safety significant systems
      (HSS) with reliability PC greater than two maintenance preventable functional failures
      (MPFFs). According to ER-AA-310-1003, Attachment 3, flowchart Process for Selecting
      Reliability Performance Criteria, HSS SSCs, with reliability PC greater than or equal to
      two MPFFs require SSC past performance documentation. When the inspectors
      requested that PSEG provide past performance documentation for the HSS SSCs with
      reliability PC greater than two MPFFs, PSEG provided documentation of HSS SSC PC
      approval from 1997, when the MRule Program was first implemented by PSEG. The
      inspectors determined this documentation did not support the assigned PC, because it
      did not consider the last 18 years of SSC past performance.
      The inspectors also reviewed ER-AA-310-1007, Maintenance Rule - Periodic (a)(3)
      Assessment. Step 5.11.1.4 states to determine that the number of MPFFs allowed per
      evaluation period is consistent with the assumptions in the probabilistic risk assessment
      (PRA). Contrary to ER-AA-310-1007, step 5.11.4, the last two periodic (a)(3)
      assessments performed by PSEG: April 1, 2011, through September 9, 2012; and
      October 1, 2012 through June 30, 2014; did not verify that the number of MPFFs allowed
      per evaluation period were consistent with the assumptions in the PRA. Additionally,
      ER-AA-310-1003, step 4.3.2, states, in part, that unless justified and approved by the
      Maintenance Rule Expert Panel, the number of MPFFs selected, as a Reliability PC,
      may not be higher than the PRA-supplied number of functional failures.
      The inspectors determined that the failure to meet ER-AA-310-1007, step 5.11.4, and
      ER-AA-310-1003, step 4.3.2, was a performance deficiency. However, at the time of
      inspection, as documented in the IR referenced above, the inspectors did not have the
      information needed to determine whether the performance deficiency was more than
      minor. The inspectors reviewed PSEGs actions in response to the URI, to determine
      whether the performance or condition of HSS SSCs was effectively controlled through
      the performance of appropriate preventive maintenance under 10 CFR 50.65(a)(2), and
      also to determine if those HSS SSCs being monitored under 10 CFR 50.65(a)(1) were
      assigned appropriate goals and monitoring when considered against the appropriate
      reliability PC threshold.
  b. Findings
      No findings were identified.
      PSEG captured the performance deficiency associated with the URI in the CAP under
      notifications 20694641, 20699573, and 20716722. In response, the PSEG Engineer
      performed detailed reviews of all the HSS reliability performance criteria against the
      basic event failure assumptions in the most recent PRA model. For any systems that
                                                44
      were identified to have reliability performance criteria deviations from the PRA basic
      event failure data, performance criteria changes were proposed to more closely align
      with the PRA. Any proposed changes to system performance criteria were scheduled
      for review by the Maintenance Rule Expert Panel, including a review of system
      performance during the last 36 months. The inspectors observed a sampling of the
      Expert Panel meetings, and reviewed meeting minutes for several others. Upon
      completion of the PSEG system reviews and expert panel meetings, a total of 12 HSS
      had reliability performance criteria reductions to more closely align with PRA failure data.
      Five of the 12 systems were already being monitored under 10 CFR Part 50.65(a)(1)
      prior to the reduction in performance criteria. None of the 12 systems were moved to
      (a)(1) as a result of the performance criteria reductions. The inspectors sampled the
      performance criteria adjustments to determine if HSS classified under (a)(2) were being
      appropriately monitored, and to verify that (a)(1) systems had appropriate goals
      assigned. No performance deficiencies were identified. The inspectors determined that
      PSEGs scope of actions restored compliance with ER-AA-310-1007, step 5.11.4, and
      ER-AA-310-1003, step 4.3.2.
      This URI is closed.
.2    License Renewal Commitments Inspection - Phase I Observation of License Renewal
      Activities (71003 - 1 sample)
  a. Inspection Scope
      License renewal inspections verify the license conditions added as part of the renewed
      operating license, regulatory commitments, and selected aging management programs,
      and are implemented in accordance with 10 CFR Part 54, Requirements for the
      Renewal of Operating Licenses for Nuclear Power Plants. This inspection was
      completed during 1R24 to observe the implementation of select aging management
      program activities that are only available for observation during a refueling outage. This
      inspection is described as Phase 1 in NRC Inspection Manual Procedure 71003, Post-
      Approval Site Inspection for License Renewal and is intended to be completed during the
      last refueling outage prior to a nuclear power facility entering the period of extended
      operation.
      As part of this review the inspectors observed the implementation of aging management
      programs and activities described in the license conditions, and regulatory commitments,
      as well as any testing or visual inspections of systems, structures, and components
      which are only accessible at reduced power levels or during a refueling outage.
      The inspectors observed the ultrasonic thickness inspection of 1S-FWR-P-21-L1, which
      is a 6-inch diameter elbow in the Feedwater Recirculation system. The component is
      part of the No. 12 SG Feed pumps 24-inch discharge header. The inspectors observed
      the test grid being applied and the recording of measurements in accordance with test
      procedure OU-AA-335-004 under the flow accelerated program guidance
      ER-AA-430-1001 as directed by WO 30285966.
      The inspectors also observed the preparation for the replacement of a Moisture
      Separator Reheat Drain system 4-inch diameter piping section. The line is the drain
      from the No. 11 West Moisture Separator Reheat Main Steam Coil going to the No. 11
      West Main Steam Coil Drain Tank. This was the planned replacement of 27 feet of
                                                45
    piping with corrosion resistant P22/Chrome Moly material. The work was being
    performed on the 140 Turbine deck, under WO 60123316.
    The inspectors observed the No. 12C Miscellaneous Drains drain manifold replacement
    spool piece. This 12-inch diameter manifold receives three drain lines from the No. 15A,
    B, & C Bleed Steam lines and is being replaced with corrosion resistant P22 (Chrome
    Moly) material. The replacement was in progress and performed under WO 60123347.
    After reviewing WO 60120251, the inspectors observed the removal and evaluation of
    random samples of inaccessible Salem Unit 1 containment liner covered by insulation.
    The inspectors observed the containment interior liner insulation being removed,
    unremediated containment liner sections, and containment liner sections that were
    cleaned, brushed, and prepared for panel installation. The inspectors reviewed
    ultrasonic thickness data to verify whether the program was in conformance with
    American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,
    Section XI.
  b. Findings and Observations
    No findings were identified.
4OA6 Meetings, Including Exit
    On July 28, 2016, the inspectors presented the inspection results to Mr. Robert DeNight,
    Salem Operations Director, and other members of the PSEG staff. On August 11, 2016,
    an additional exit meeting was conducted and the inspectors presented inspection
    results specific to the baffle bolt issues in this report to Mr. Eric Carr, Acting Station Vice
    President. During the August 11, 2016 exit meeting, PSEG management stated they
    may contest NCV 05000311/2016002-02 (Section 1R15), in a written response within
    30 days of the date of this inspection report, using the process described in the cover
    letter. Additionally, the inspectors verified that no proprietary information was retained
    by the inspectors or documented in this report.
4OA7 Licensee-Identified Violations
    The following violation of very low safety significance (Green) was identified by PSEG
    and is a violation of NRC requirements which meets the criteria of the NRC Enforcement
    Policy, for being dispositioned as an NCV.
        TS LCO 3.3.2.1 requires the ESFAS instrumentation channels and interlocks shown
          in Table 3.3-3 shall be operable. Table 3.3-3, Function 8, requires two channels of
          AFW automatic actuation logic to be operable in Modes 1, 2, and 3. With the
          number of operable channels one less than the required number of channels, TS
          LCO 3.3.2.1 requires the inoperable channel to be restored to operable status within
          6 hours or, be in at least Hot Standby within the next 6 hours and in at least Hot
          Shutdown within the following 6 hours. Contrary to TS LCO 3.3.2.1, one less than
          the required number of channels of AFW automatic actuation logic were operable
          from April 20, 2015, until Unit 2 entered Mode 4 for a scheduled refueling outage on
          October 23, 2015. This was due to the 21 AFW pump loop time response being
          greater than the allowed TS value because the isolation valve for the pressure
                                            46
      override defeat pressure transmitter was in the closed position. PSEG entered this
      issue into the CAP as NOTFs 20709417, 20716352, 20710947, and 20711796.
      This performance deficiency was more than minor because it was associated with
      the human performance attribute of the Mitigating System cornerstone, and
      adversely affected the cornerstone objective of ensuring the reliability and capability
      of systems that respond to initiating events to prevent undesirable consequences.
      The inspectors evaluated this finding using IMC 0609, Appendix A, The Significance
      Determination Process for Findings At-Power, Exhibit 2. The inspectors determined
      that the finding was of very low safety significance (Green) because the finding did
      not represent an actual loss of function of at least a single train for greater than its
      TS allowed outage time.
ATTACHMENT: SUPPLEMENTARY INFORMATION
                                              A-1
                              SUPPLEMENTARY INFORMATION
                                  KEY POINTS OF CONTACT
Licensee Personnel
J. Perry, Site Vice President
E. Carr, Acting Site Vice President
J. Barkhamer, PSEG Engineer
J. Bergeron, Superintendent of Instrumentation and Controls
T. Cachaza, Senior Regulatory Compliance Engineer
R. Cary, Environmental Coordinator
L. Clark, Instrument Supervisor
B. Daly, Nuclear Environmental Affairs, Sustainability
D. Denelsbeck, RP Support Supervisor
B. Down, PSEG Engineer
P. Essner, System Engineer
P. Fabian, Salem Steam Generator Engineer
T. Giles, Salem ASME Section XI Program Owner
F. Grenier, RP Supervisor, Dosimetry
M. Hassler, Salem Radiation Protection Manager
B. Kerkorian, Salem Steam Generator Supervisor
D. Kolasinski, Senior Engineer
A. Kraus, Manager, Nuclear Environmental Affairs
T. MacEwen, Principal Compliance Engineer
J. Mallon, Compliance Director
S. Markos, Manager, Design Engineering
J. Marooney, MPR Engineering Consultant
P. Martitz, Technical Support Superintendent
J. Melchionna, Engineering Services
R. Moore, System Engineering Branch Manager
D. Mora, Salem NDE Program Coordinator
G. Morrison, Mechanical Engineer
T. Mulholland, Shift Operations Manager
A. Ochoa, Senior Compliance Engineer
B. Ohmert, System Engineer
T. Oliveri, Salem Unit 1 and Unit 2, NDE Manager
J. ORourke, Regulatory Affairs
J. Owad, Design Engineering
M. Phillips, Regulatory Assurance
M. Pyle, Chemistry Manager
N. Ruvis, Westinghouse
B. Sebastian, Manager Fire Protection/Industrial Safety
J. Stairs, Manager Plant Engineering
C. Wend, Radiation Protection Manager
D. Yilgic, Lead Engineer Quality Control Chemistry
                                                            Attachment
                                    A-2
                LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Open
05000272/2016002-01            URI        Baffle-Former Bolts with Identified
                                          Anomalies (Section 1R08)
Open and Closed
05000311/2016002-02            NCV        Failure to Follow Operability
                                          Determination Procedure for Unit 2
                                          Baffle-Former Bolts (Section 1R15)
05000311/2016002-03            FIN        Inadequate Work Order Planning Results in
                                          Main Generator AVR STV Relay Trip
                                          (Section 4OA3.3)
Closed
05000272:311/2015-008-01      URI        Inadequate Maintenance Rule System
                                          Performance Criteria Selection
                                          (Section 4OA5)
05000311/2016-001-00          LER        Auxiliary Feedwater Loop Response Time
                                          Exceeded Technical Specifications
                                          (Section 4OA3.1)
05000311/2016-002-00          LER        Automatic Reactor Trip Due to Main
                                          Turbine Trip (Section 4OA3.3)
                                              A-3
                                LIST OF DOCUMENTS REVIEWED
* Indicates NRC-identified
Section 1R01: Adverse Weather Protection
Procedures
SC.OP-SO.500-0001, Trip-A-Unit Scheme Operation, Revision 10
OP-AA-108-107-1001, Electric System Emergency Operations and Electric Systems Operator
        Interface, Revision 4
Notifications
20731655*      20731657*      20731658*    20731659*      20731662    20731729*
20731735*
Section 1R04: Equipment Alignment
Procedures
SC.MD-ST.125-0003, Quarterly Inspection and Preventive Maintenance of Units 1, 2, & 3 125
        Volt Station Batteries, Revision 30
S1.OP-ST.CAN-0007, Refueling Operations - Containment Closure, Revision 25
S2.OP-SO.SW-0005, Service Water System Operation, Revision 42
S2.OP-SO.ABV-0001, Auxiliary Building Ventilation System Operation, Revision 25
S2.OP-SO.SJ-00001, Preparation of the Safety Injection System for Operation, Revision 19
OP-SA-102-106, Salem Operations Master List of Timed Actions, Revision 0
OP-AA-108-103, Locked Equipment Program, Revision 4
Notifications
20702800        20707221        20724871    20729878*      20732182    20732551
20732785*      20732994*      20733091
Drawings
205337, Sheet 1, No. 2 Unit Auxiliary Building - Ventilation, Revision 43
205242, Sheet 1, No. 2 Unit Service Water Nuclear Area, Revision 81
205242, Sheet 2, No. 2 Unit Service Water Nuclear Area, Revision 76
Maintenance Orders/Work Orders
50180453        50182431        60125981    60129782
Section 1R05: Fire Protection
Procedures
FP-SA-2542, Pre-Fire Plan Unit 2 Spent Fuel/Component Cooling Heat Exchanger and Pump
        Area, Revision 0
FP-SA-2552, Pre-Fire Plan Unit 2 Boric Acid Evaporator Unit & Chemistry Area, Revision 0
FP-SA-2651, Pre-Fire Plan Unit 2 Service Water Intake Structure, Revision 0
FP-SA-2555, Pre-Fire Plan Unit 2 Diesel Generator Area, Revision 0
FP-SA-2556, Pre-Fire Plan Unit 2 Inner Piping Penetration Area & Chiller, Revision 0
                                            A-4
Notifications
20723743      20730150*    20732820*    20732836*
Section 1R07: Heat Sink Performance
Notifications
20726947
20727041
20727041
Maintenance Orders/Work Orders
30255437
Section 1R08: In-service Inspection
NDE Procedures
Liquid Penetrant Examination Procedure, OU-AA-335-002, Revision 3
Nondestructive Examination Procedure, Manual Ultrasonic Examination of Vessel Nozzle Inner
        Radius Regions, Procedure Number 54-ISI-132-011, 1/27/2011
Nondestructive Examination Procedure, Ultrasonic Examination of Austenitic Piping Welds,
        Procedure Number 54-ISI-836-014, 8/21/2013
Areva NP Inc., Nondestructive Examination Procedure, Multi-Frequency Eddy Current
        Examination of Tubing, Procedure Number 54-ISI-400-021, 6/12/2013
Notifications
20682192      20694861      20697140      20697577      20697669      20699820
20699859      20699910      20704139      20707057      20707057      20707125
20712181      20712774      20713572      20713573      20713849      20713849
20714082      20716581      20720745      20722494      20724667      20725857
20726340      20726743
Maintenance Orders/Work Orders
60114705
60123261
60126260
Evaluations
70178672      70178814      70178821      70179375      70183001      70185980
Self Assessments
Check-In Self-Assessment, Salem INPO PWR Materials Review, 7/30/2015
NDE Records
Salem Unit 1, Liquid Penetrant Report No. PT-16-002, 11-RHRHEX Vessel Support, 4/15/16
        (Summary No.205170)
Salem Unit 1, Liquid Penetrant Report No. PT-16-001, Pipe Lugs 8-RH-2116-10PL-1 thru 4,
        4/15/16 (Summary No. 263631)
Salem Unit 1, Liquid Penetrant Report No. PT-16-004, Pipe to Penetration IA, Component 12
        SJ-2152-36PS-4, 4/19/16 (Summary No. 263904)
                                                  A-5
Salem Unit 1, Liquid Penetrant Report No. PT-16-003, Inlet Nozzle-to-Pump (11 Charging
        Pump), Component 6-CV-2111-14R1, 4/15/16 (Summary No. 220757)
        Salem Unit 1, Liquid Penetrant Report No. PT-16-005, PIPE TO VALVE (11CS48)
        component ID: 8-CS-2114-60, 4/15/16 (Summary No. 356640)
Design Change Package
80092579, Salem Unit 1 - Steam Generator Bowl Drain Repair, SG 11, 12, 13, and 14 (removal
        of Alloy 600 and associated 82/182 weld material from each SG Channel Head (SGCH)
        bowl drain plugs
PSEG NUCLEAR VTD NUMBER: 900013(019), Title Stress Analysis of Tube-Tubesheet Weld
        AREVA RSG, 11/23/15; Calculation Summary Sheet, 7/25/2015.
PSEG Nuclear Work Order 70172201; Areva Reanalysis of Salem Steam Generator tube-to-
        tubesheet joint as a friction joint and to provide a revised SG stress analysis to PSEG for
        record purposes
WO #60123261, including weld history sheet; Replace SISJ - !SJ248 & 2SJ249
PSEG NUCLEAR LLC VTD NUMBER: AREVA 902739 (001); Salem Unit 1 SG Condition
Monitoring for 1R22 AND Final Operational Assessment for Cycles 23 & 24; 8/8/13
Drawings: 02-9124528D, Salem Unit 1 Steam Generator Channel Head Drain
        Modification, Revision 001
Drawings: 1512E32, Salem REPLACEMENT Steam Generator General Layout; Salem
        Unit 1 Steam Generator Channel Head Drain Modification, Revision 1
Drawing 02-9124526B, Revision 001, Steam Generator Channel Head Drain Plug
Document No.: 51-9207624-000, Salem Unit 1 SG Condition Monitoring for 1R22 and Final
        Operational Assessment for Cycles 23 & 24
Other Documents
NRC Regulatory Issues Summary 2016-02, Design Basis Issues Related To Tube-To-
        Tubesheet Joints in Pressurized-Water Reactor Steam Generators, March 23, 2016
PSEG NUCLEAR LLC VTD Number: 9000(019); AREVA Stress Analysis of Tube-Tubesheet
        Weld-AREVA, Vendor Number 32-9235210-001
Section 1R11: Licensed Operator Requalification Program
Other Documents
SG-1624, Risk Management, SGFP Trip, SGTR, dated 05/21/16
Section 1R12: Maintenance Effectiveness
Procedures
ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Revision 14
Notifications
20689987        20729117*      20730512*      20730513*      20731038*    20732228*
Drawings
265029, Circ Water Swgr Bldg. 125VDC DC Distribution System, Revision 5
                                              A-6
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
OP-AA-108-116, Protected Equipment Program, Revision 12
Notifications
20723781      20724495      20725030*      20725036      20726192    20727564
20727565      20728242      20731749      20733122
Maintenance Orders/Work Orders
60128649
Other Documents
ACE 20723873, 11 CFCU Low Speed Breaker Back-Flashed
Section 1R15: Operability Determinations and Functionality Assessments
Calculations, Analysis, Engineering Evaluations, and Specifications
MPR Associates Letter "Salem Service Water Discharge Header - Disposition of Degraded
  Joints", (0108-0471-0007, Rev 1), 6/3/2016
MPR Associates Letter, Salem PCCP Bell-and-Spigot Joint Degradation-Supplemental
  Information to (MPR-2650 Revision 0), 10/26/05
MPR Associates Letter, Salem Service Water Discharge Header - Disposition of Degraded
  Joints (0108-0471-0007, Rev 0), 4/29/2016
MPR Calculation 0108-0333-JEM-01, Structural Evaluation of Service Water Piping Thinned
  Joints, Revision 0
PSEG VTD 326511-001, "Structural Evaluation of Service Water Piping Thinned Joints"
PSEG VTD 326511-002, "Service Water
PSEG VTD 326511-003, "Service Water WEKO Seal Structural Repair Relief Request RAI
  Response Technical Input"
PSEG VTD 326511-004, "Request for Use of Mechanical Repair System in Degraded Service
  Water Pipe Joints - Input for Response to NRG Request for Additional Information dated
  October 29, 2013"
S-C-SW-MEE-1975, Salem Units 1 & 2 Concrete Service Water Pipe Joints - Acceptance
  Criteria, Revision 0
Drawings, Wiring Diagrams, and Piping and Instrumentation Diagrams
205243, Sheet 1, Auxiliary Building Control Air, Revision 49
0108-0471-0007, Salem Service Water Discharge Header - Disposition of Degraded Joints,
  4/29/2016
Evaluations
70097092      70097514      70103845      70131286      70144770
Notifications
20724198      20726264      20727538      20727590      20726001
20726320      20727126      20727354      20727430      20727678
20729040      20730485*      20727242      20727261
                                              A-7
Procedures
CC-AA-309-101, Engineering Technical Evaluation, Revision 10
OP-AA-108-115, Operability Determinations & Functionality Assessments, Revision 4
LS-AA-120, Issue Identification and Screening Process, Revision 13
LS-AA-125, Corrective Action Program, Revision 21
NO-AA-10, Quality Assurance Topical Report (QATR), Revision 84
S1.OP-PT.CA-0001, Emergency Control Air Compressor Functional Test, Revision 18
S1.OP-LR.CA-0005, Leak Rate Test 1CA920, Revision 1
SC.OP-LB.DF-0001, Diesel Fuel Oil Testing Program, Revision 3
Maintenance Orders/Work Orders
30265178      50140453      50154389      50154555      50158970        50172136
60115402
Miscellaneous
Inspection Manual Chapter 0326, Operability Determinations & Functionality Assessments for
      Conditions Adverse to Quality or Safety, dated December 3, 2015
Event Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel
      Internals, dated May 3, 2016
70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure,
      Revision 0
70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure,
      Revision 1
OpEval 2016-015, Potentially Degraded Baffle-Former Bolts in Salem Unit 2, Revision 0
80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0
80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1
S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,
      Revision 0
S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,
      Revision 1
80117136 SUP01, Map of Degraded Bolt Locations, Revision 0
Westinghouse LTR-RIDA-16-125, Rev. 2, Salem Unit 1 Baffle Bolting One Cycle Replacement
      Pattern Summary Letter, dated May 31, 2016
WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2,
      Revision 0
ML13093A382, Request for Relief from ASME Code Defect Removal for Service Water Buried
    Piping, 4/3/2013
ML13227A338, PSEG Response to Request for Additional Information- Relief Request SC-14R-
    133, Alternative Repair for Service Water System Piping, 8/15/13
ML14016A123, PSEG Response to Request for Additional Information (RAI 31 and RAI 32) -
    Relief Request SC-14R-1 33, Alternative Repair for Service Water System Piping, 1/8/14
ML14058A228, PSEG Response to Request for Additional Information (RA133 - RAI36)-Relief
    Request SC-14R-133, Alternative Repair for Service Water System Piping, 2/27/14
ML14085A482, PSEG Response to Request for Additional Information (RAJ 37) - Relief
    Request SC-14R-133, Alternative Repair for Service Water System Piping, 3/26/14
ML14097A029, Salem Nuclear Generating Station, Units 1 And 2- Safety Evaluation of Relief
    Request No. SC-14R-133 for the Alternative Repair for Service Water System Piping (TAC
    NOS. MF1375 AND MF1376), 4/8/2014
                                              A-8
Modifications
80110461
Other Documents
ML13093A382, Request for Relief from ASME Code Defect Removal for Service Water Buried
    Piping, 4/3/2013
ML13227A338, PSEG Response to Request for Additional Information- Relief Request SC-14R-
    133, Alternative Repair for Service Water System Piping, 8/15/13
ML14016A123, PSEG Response to Request for Additional Information (RAI 31 and RAI 32) -
    Relief Request SC-14R-1 33, Alternative Repair for Service Water System Piping, 1/8/14
ML14058A228, PSEG Response to Request for Additional Information (RA133 - RAI36)-Relief
    Request SC-14R-133, Alternative Repair for Service Water System Piping, 2/27/14
ML14085A482, PSEG Response to Request for Additional Information (RAJ 37) - Relief
    Request SC-14R-133, Alternative Repair for Service Water System Piping, 3/26/14
ML14097A029, Salem Nuclear Generating Station, Units 1 And 2- Safety Evaluation of Relief
Request No. SC-14R-133 for the Alternative Repair for Service Water System Piping (TAC
NOS. MF1375 AND MF1376), 4/8/2014
Section 1R18: Plant Modifications
Condition Reports
20733528      20733526      20726264      20735142
Other Documents
80117136, Design Change Package for Salem Unit 1 Baffle-to-Former Bolt Replacement,
      Revision 0
80117378, Item Equivalency Evaluation for Replacement Baffle Bolts, dated 6/2/2016
EVAL-16-19, Salem Unit 1 Baffle-Former Bolt Replacement 1R24, Revision 0
LTR-RIAM-16-39, Transmittal of Westinghouse Specification 70041 EB to PSEG, dated
      5/4/2016
S2016-156, 50.59 Screening Form for DCP 80117136, Revision 0
WCAP-18144-P, Generic Replacement Type 316 Cold-Worked Baffle-Former Bolt Qualification
      for 4-Loop Downflow Plants, Revision 0
Procedures
54-ISI-364-00, Remote Underwater In-Vessel Visual Inspection of Reactor Pressure Vessels,
      Vessel Internals, and Components in Pressurized Water Reactors, dated August 22,
      2000
54-ISI-372-005, Remote Underwater In-Vessel Visual Inspection of Baffle to Former Bolts and
      Baffle Edge Bolts, dated September 23, 2011
54-UT-108-001, Ultrasonic Inspection of Internal Hex Head Baffle Bolts, dated April 24, 2011
GBRA 104650, Work Instruction Bolt Removal, Revision D
GBRA 173122, Repair and Inspection Sequence Plan for Baffle-former Bolt Replacement at
      NPP Salem, Revision 00
                                              A-9
Miscellaneous
180-9257342-000, NDE Services Final Report, Salem Unit 1, 1R24 Baffle to Former Plate Bolt
        Inspection Report, dated June 2, 2016
51-9256526-000, Technical Justification for Internal Hex Head E Baffle to Former Bolts
        Volumetric Examination at Westinghouse 4-Loop Reactors, dated April 25, 2016
IVVI-101, 01RF Examination Summary Record, VT-3 of Upper Core and Support Plate, dated
        5/9/2001
Inservice Inspection Results, Bolt ID 5-55-C, dated May 3, 2016
Inservice Inspection Results, Bolt ID 6-75-C, dated April 30, 2016
NDE Personnel Qualification and Certification, VT-1, 2, & 3, Employee 16657, dated March 7,
        2016
NDE Personnel Qualification and Certification, VT-1, 2, & 3, Employee 114882, dated March 4.
        2015
MRP-228, Materials Reliability Program: Inspection Standard for PWR Internals- 2012 Update,
        Revision 1
54-UT-108-001, Ultrasonic Inspection of Internal Hex Head Baffle Bolts, Revision 1
80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0
80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1
S2016-156, 50.59 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,
        Revision 0
S2016-156, 50.59 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,
        Revision 1
80117136 SUP01, Map of Degraded Bolt Locations, Revision 0
Westinghouse LTR-RIDA-16-125, Rev. 2, Salem Unit 1 Baffle Bolting One Cycle Replacement
        Pattern Summary Letter, dated May 31, 2016
Westinghouse LTR-RIDA-16-125, Rev. 3, Salem Unit 1 Baffle Bolting One Cycle Replacement
        Pattern Summary Letter, dated July 11, 2016
WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2,
        Revision 0
WCAP-18144-P, Generic Replacement Type 316 Cold-Worked Baffle-Former Bolt Qualification
        for 4-Loop Downflow Plants, Revision 0
VEN-16-041, Remote Visual Examination: Baffle-former Bolts (Core Side), dated July 27, 2016
Section 1R19: Post-Maintenance Testing
Procedures
SC.MD-PM.CBV-0002, CFCU Motor Heat Exchanger Internal Inspection, Revision 20
SC.MD-PM.SW-0012, Enecon Tubesheet Cladding System, Revision 13
SC.IC-TI.ZZ-0104, Configuration Control for NUS Model MTH801 Summators, Revision 32
S2.IC-CC.RCP-0058, 2FT-542 #24 Steam Generator Flow Protection Channel I, Revision 42
Notifications
20273570        20670175      20672463      20723478      20723652      20723765
20724185        20724217      20725095      20725111      20726481      20727534
Maintenance Orders/Work Orders
30205173        60120462      60128697      60129161
                                              A-10
Evaluations
70171681
Section 1R20: Refueling and Other Outage Activities
Procedures
LS-AA-119-1003, Calculating Work Hours, Revision 7
MA-AA-716-008-1010, Reactor Services Project FME Plan, Revision 2
S1.OP-IO.ZZ-0006, Hot Standby to Cold Shutdown, Revision 37
S1.OP-TM.ZZ-0001, Reactor Coolant System Pressure - Temperature Curves, Revision 4
SC.OP-DL.ZZ-0001, Reactor Coolant System Heatup/Cooldown Log, Revision 9
SC.OP-DL.ZZ-00012, Pressurizer Heatup/Cooldown Log, Revision 5
Notifications
20723957      20725589*      20725843      20725856  20725917    20726061*
20726121      20726355        20727113      20727298  20727697    20729566
Other Documents
1R24 Shutdown Safety Evaluation and Approval, dated 03/25/16
Section 1R22: Surveillance Testing
Procedures
S2.OP-ST.RHR-0001, Inservice Testing - 21 Residual Heat Removal Pump, Revision 29
S2.RA-ST.RHR-0001, Inservice Testing 21 Residual Heat Removal Pump Acceptance Criteria,
        Revision 12
S1.OP-ST.SSP-0001, Manual Safety Injection - SSPS, Revision 32
Notifications
20725279*      20725282*      20725581      20725603  20725936    20726147
20726148      20726342        20728892*    20728962* 20728963*
Maintenance Orders/Work Orders
50182657
Other Documents
Unit 1 Operator logs for April 17 and 18, 2016
Section 1EP6: Drill Evaluation
Procedures
NC.EP-EP.ZZ-0405, Emergency Termination - Redaction - Recovery, Revision
S2.OP-AB.Fuel-0001, Fuel Handling Incident, Revision 5
S2.OP-AB.CW-0001, Circulating Water System Malfunction, Revision 36
S2.OP-AB.CVC-0001, Loss of Charging, Revision 9
Notifications
20733529
20733001
                                                A-11
Other Documents
S16-01, Salem All Facilities Training Drill, 06/16/16
Section 2RS1: Access Control to Radiologically Significant Areas
Procedures
RP-AA-301, Radiological Air Sampling Program, Revision 6
RP-AA-460, Control for High and Very High Radiation Areas, Revision 17
RP-AA-463, High Radiation Area Key Control, Revision 4
RP-AA-401-1001, Special Instruction for Highly Radioactive In-core Components, Revision 0
RP-SA-103, Radiological Control of Reactor Cavity and Spent Fuel Pool Operations, Revision 1
RP-AA-210, Dosimetry Issue, Usage, and Control, Revision 13
RP-AA-401, Operational ALARA Planning and Control, Revision 13
Other Documents
Audits
Locked High Radiation Key Inventory Logs
Radiation Protection Job Guides (7 through 14)
Radiological Survey data (various)
Radiation Protection Plant Radionuclide Evaluation
Corrective Action Documents (various Notifications)
Section 2RS2: Occupational ALARA Planning and Controls
Procedures
RP-AA-401, Operational ALARA Planning and Control, Revision 13
CY-AP-120-1030, Estimating RCS Crud Release for Refueling Outage, Revision 1
S1. CH-IO.ZZ-111(Z), Salem Unit 1 Shutdown Chemistry Plan, Revision 8
Other Documents
Refueling Outage Radiological Performance Report
ALARA Plans (various)
Radiation Protection Job Guides (7 through 14)
ALARA Work In-process Reviews
Outage Chemistry Control Plan
1R24 Hard Gamma Projection
Corrective Action Documents (various Notifications)
Section 2RS3: In-plant Airborne Radioactivity Control and Mitigation
Procedures
RP-SA-103, Radiological Control of Reactor Cavity and Spent Fuel Pool Operations, Revision 1
RP-AA-220, Annual Bioassay Review, Revision 9
RP-AA-301, Radiological Air Sampling Program, Revision 6
RP-AA-401, Operational ALARA Planning and Control, Revision 13
NF-AA-430, Failed Fuel Action Plan, Revision 8
                                              A-12
Other Documents
Radiological Source Term Data - 10 CFR 61 waste stream report
Airborne Radioactivity Sampling Results (various)
Corrective Action Documents (various Notifications)
Section 2RS4: Occupational Dose Assessment
Procedures
RP-AA-401, Operational ALARA Planning and Control, Revision 13
Other Documents
Radiation Protection Job Guides (7 through 14)
General Source Term Data (various)
Corrective Action Documents (various notifications)
Section 2RS5: Radiation Monitoring Instrumentation
Procedures
RP-AA-301, Radiological Air Sampling Program, Revision 6
RP-AA-504, Routine Operation of the Radiation Protection Gross Counting facility
Other Documents
Instrument Source Check and Operability data (various)
Corrective Action Documents (various notifications)
Section 2RS7: Radiological Environmental Monitoring Program
Procedures
RP-AA-228, 10 CFR 50.75(g0 and 10 CFR 50.72.30(d) Documentation, Revision 3
EN-AA-170-500, Meteorological Monitoring System Calibration and Maintenance (Metrological
        Tower), Revision 1
EN-AA-170-1000, Radiological Environmental Monitoring Program (REMP) and Meteorological
        Program (MET) Implementation, Revision 1
EN-AA-1001, REMP Vendor Dosimetry and Laboratory QA Program
EN-AA-170-4000, Radiological Ground water Protection program Implementation, Revision 0
EN-AA-170-4160, Station RGPP Controlled sample Points, Revision 0
EN-AA-170-4200, Disposal of Water from Excavation projects, Revision 0
EN-AA0170-4300, Investigative Process for Evaluation of Anomalous Tritium Data from On-site
        Wells, Revision 1
CY-AA-170-400, Radiological Ground water protection program, Revision 4
AD-LTS-10, Laboratory and Testing Service (LTS) Quality Assurance Program, Revision 4
Instruction NASSV-1.2.2NS, Service of Low Volume Sampler, Revision 19
Instruction MLKSA-1.1.2, Collection of Raw Milk samples, Revision 12
Instruction VGTSA-1.1.7, Collection of Vegetable, Vegetation and Fodder Crops, Revision 8
Instruction 1.1.9, Collection of Potable Water Samples, Revision 3
Instruction TLDSV-1.2.1, Installation of Area Monitoring Dosimeters in the Field, Revision 16
Instruction AQUACOLL-1.1.10, Collection of Aquatic samples, Revision 11
Instruction GMSA -1.1.11, Collection of Game samples, Revision 3
Instruction VEGECEN-0.3.2, Salem/Hope Creek Vegetable Garden Census, Revision 6
                                              A-13
Instruction NRESCEN, Salem/Hope Creek Nearest Resident Census, Revision 5
Instruction MLKCEN 0.3.1, Salem/Hope Creek Census of Milk Animals, Revision 6
Instruction H2OSA-1.1.1, Collection of Water Samples, Revision 13
Instruction SOLSA -1.1.3, Collection of Soil Samples, Revision 8
Instruction ESS-1.1.5, Collection of Sediment Samples, Revision 9
Instruction ESFCH -1.1.6, Pickup of Fish and Crab Samples, Revision 7
Other Documents
Salem and Hope Creek Offsite Dose Calculation Manuals (ODCM)
UFSAR Section 11.6, Offsite Radiological Monitoring Program
Hope Creek Nuclear Station Buried and Underground Piping Asset Management Plan,
        Revision 0
Salem and Hope Creek 2015 Annual Effluent Releases Reports
NEI-07-07, Structure, System, Component (SCC) Review for Turbine Roof Structure (Hope
        Creek)
Salem and Hope Creek Annual Radiological Environmental Monitoring Reports
Salem/Hope Creek Meteorological Program Status Report (2014, 2015)
Salem/Hope Creek Metrological Tower Updated Vegetation Review, June 3, 2016
Comparison of 2015 Atmospheric Dispersion Factors for Salem and Hope Creek, dated
        March 28, 2016
Chemistry, Radwaste, Effluent and Environmental Monitoring Audit Report, NOSA-SLM-16-04,
        May 11, 2016
2016 Self-Assessment REMP Program Inspection
Teledyne Brown Environmental Service Annual Quality Assurance Report
GEL 2015 - Annual Quality Assurance Report (REMP)
Residential Survey, dated December 22, 2015
Milk Animal Survey dated December 2015
Vegetable garden Survey dated August 2015
Calibration Data (Dry Gas Meters 61182898, 14522708, 2424590)
Calibration Data (Laminar Flow Element 16300942)
Global Solutions Annual Testing, dated May 26, 2015
Passive Environmental Dosimetry Calibration data
Ground Water Monitoring Data and RGPP Data
Salem/Hope Creek Part 61 Analysis Review, dated April 27, 2016
Salem Remedial Action Plan Progress Reports
Corrective Action Documents (various Notifications)
Ground Water Monitoring Data
Corrective Action Documents (various Notifications)
Section 4OA2: Problem Identification and Resolution
Condition Reports
20724198      20726264      20727538        20727590    20728329    20732892
20731786      20725142      20736630
Maintenance Orders/Work Orders
70136205      70140618      70154315        70168067    70168874    70180750
70182469      70182519      70183590        70183629
                                                A-14
Miscellaneous
Westinghouse LTR-RIDA-16-125, Rev. 2, Salem Unit 1 Baffle Bolting One Cycle Replacement
        Pattern Summary Letter, dated May 31, 2016
Westinghouse LTR-RIDA-16-125, Rev. 3, Salem Unit 1 Baffle Bolting One Cycle Replacement
        Pattern Summary Letter, dated July 11, 2016
WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2,
        Revision 0
Non-Proprietary Safety Evaluation of WCAP-17096-NP, Revision 2, Reactor Internals
        Acceptance Criteria Methodology and Data Requirements (TAC No. ME4200). (ADAMS
        Accession No. ML16061A243), dated May 3, 2016
Westinghouse Calculation Note, CN-RIDA-15-34, Rev. 4, Units 1 and 2 Acceptable Baffle-
        Former LOCA and Seismic Analysis, dated May 16, 2016
Westinghouse Calculation Note CN-RIDA-15-64, Rev. 2, Salem Units 1 and 2 Acceptable
        Baffle-Former Bolting Pattern Fuel Grid Impact Analysis, dated May 16, 2016
Event Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel
        Internals, dated May 3, 2016
80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0
80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1
S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,
        Revision 0
S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,
        Revision 1
80117136 SUP01, Map of Degraded Bolt Locations, Revision 0
Westinghouse LTR-RIDA-16-112, Rev. 0, Summary of Salem Unit 1 Baffle-Former Bolt Real-
        time Analysis Results, dated May 11, 2016
WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2,
        Revision 0
Westinghouse LTR-RIAM-16-38 Rev. 0, Salem Unit 1 Real-Time Analysis Results for
        LOCA/Seismic Dynamic Analysis and Fuel Grid Impact Analysis, dated May 3, 2016
Westinghouse LTR-RIAM-16-39 Rev. 0, Transmittal of Westinghouse Specification 70041 EB to
        Public Service Enterprise Group, dated May 4, 2016
Information Notice 98-11, Cracking of Reactor Vessel Internal Baffle-former Bolts in Foreign
        Plants, dated March 24, 1998
Eval-16-19, Westinghouse Electric Company 10 CFR 50.59 Applicability Determination, Salem
        Unit 1 Baffle-former Bole Replacement 1R24, Revision 0
MRP-228, Materials Reliability Program: Inspection Standard for PWR Internals - 2012 Update,
        Revision 1
Unit 1 and 2 Technical Specifications, Revision 28
ACM 16-011, Baffle Plates Monitoring, dated June 17, 2016
ACM 16-011, Baffle Plates Monitoring, dated July 25, 2016
WCAP-15030-NP-A, Westinghouse Methodology for Evaluating the Acceptability of Baffle-
        Former-Barrel Bolting Distributions Under Faulted Load Conditions, dated January 1999
NRC Safety Evaluation of Topical Report wCAP-25029, Westinghouse Methodology for
        Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions Under Faulted
        Load Conditions (TAC No. MA1152), dated November 16, 1998
NRC Letter, Leak Before Break Evaluation of Primary Loop Piping, Salem Nuclear Generating
        Station, Units 1 and 2 (TAC NOS. M85799 and M85800), dated May 25, 1994
51-92566526, Technical Justification for Internal Hex Head E Baffle to Former Bolts Volumetric
        Examination at Westinghouse 4-Loop Reactors, dated April 28 2016
                                              A-15
54-ISI-364-00, IVVI Inspection Data Sheet Salem 1R14, dated May 8, 2001
Areva Letter, Completion and Status of Octants 1, 2, 3, 4, 5, 6, 7, and 8 (i.e., 1-8), dated May 5,
        2016
OTDM 16-005, Salem Unit 2 Baffle to Former Bolting of Reactor Vessel Internals, dated June
        16, 2016
WCAP-18144-P, Generic Replacement Type 316 Cold-Worked Baffle-Former Bolt Qualification
        for 4-Loop Downflow Plants, Revision 0
Westinghouse LTR-LIS-11-381, LOCA Assessment of Core Coolable Geometry for Grid
        Deformation in Peripheral Fuel Assemblies, dated June 27, 2011
Event Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel
        Internals, dated May 3, 2016
70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure,
        Revision 0
70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure,
        Revision 0
Op Eval 2016-015, Potentially Degraded Baffle-Former Bolts in Salem Unit 2, Revision 0
VEN-16-041, Remote Visual Examination Baffle-former Bolts (Core Side), dated July 27, 2016
Procedures
ER-AA-2003, System Performance Monitoring and Analysis, Revision 10
54-ISI-364-00, Remote Underwater In-Vessel Visual Inspection of Reactor Pressure Vessels,
        Vessel Internals, and Components in Pressurized Water Reactors, dated August 22,
        2000
54-UT-108-001, Ultrasonic Inspection of Internal Hex Head Baffle Bolts, dated April 28, 2016
Notifications
20704666        20706027      20709417      20710340*      20710947        20711723
20711796        20715617      20716352      20716358      20716401        20716402
20716404        20716754      20721375      20726684      20728492*        20730946
20734279*      20734280*    20734281*      20734284*      20734286*        20734856*
Other Documents
S2.OP-ST.SSP-0011(Q), Engineered Safety Features Response Time Testing performed
        October 18, 2015
NRC Event Notification 51663
Exelon PowerLabs Report PSE-65422, 07/01/13
Exelon PowerLabs Report PSE-82817, 11/13/13
Exelon PowerLabs Report PSE-00915, 03/18/14
Exelon PowerLabs Report PSE-19717, 10/22/15
Exelon PowerLabs Report PSE-88030, Draft
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
Notifications
20733919*
                                A-16
                        LIST OF ACRONYMS
10 CFR Title 10 of the Code of Federal Regulations
AC    alternating current
ACE    apparent cause evaluation
ADAMS  Agencywide Documents Access and Management System
AFW    auxiliary feedwater
ALARA  as low as is reasonably achievable
ASME  American Society of Mechanical Engineers
AVR    automatic voltage regulator
CAP    Corrective Action Program
CCE    common cause evaluation
CFCU  containment fan cooling unit
CFR    Code of Federal Regulations
CS    containment spray
DC    direct current
DCP    design change package
EC    eddy current
ECAC  emergency compressed air compressor
ECCS  Emergency Core Cooling System
ECT    eddy current testing
EDG    emergency diesel generator
EFPY  effective full power years
EPD    electronic personal dosimeter
EPRI  Electric Power Research Institute
ESFAS  engineered safety feature actuation system
FIN    finding
FOSAR  foreign object search and retrieval
GPI    Groundwater Protection Initiative
HRA    high radiation area
HSS    high safety significant systems
HX    heat exchanger
IMC    Inspection Manual Chapter
IOD    immediate operability determination
IR    inspection report
ISI    In-service inspection
IASCC  Irradiation Assisted Stress Corrosion Cracking
kV    kilovolt
LCO    limiting conditions for operation
LER    licensee event report
LHRA  locked high radiation area
LLRT  local leak rate test
LTS    Laboratory and Testing Services
MPFF  maintenance preventable functional failure(s)
MR    maintenance rule
MRC    Management Review Committee
NCV    non-cited violation
NDE    nondestructive examination
NEI    Nuclear Energy Institute
                              A-17
NOS  Nuclear Oversight
NOTF  notification(s)
NRC  Nuclear Regulatory Commission
NVLAP National Voluntary Laboratory Accreditation Program
ODCM  Offsite Dose Calculation Manual
PC    performance criteria
PI    performance indicator(s)
PM    preventive maintenance
PRA  probabilistic risk assessment
PSEG  Public Service Enterprise Group Nuclear LLC
QHPI  Quick Human Performance Investigation
RCE  root cause evaluation
RCS  reactor coolant system
REMP  Radiological Environmental Monitoring Program
RFO  refueling outage
RG    regulatory guide
RHR  residual heat removal
RP    radiation protection
RTO  relay test order
RWP  radiation work permit(s)
SBO  station blackout
SDP  significance determination process
SF    spent fuel
SG    steam generator
SI    safety injection
SOC  Station Oversight Committee
SSC  structure, system, and component
SW    service water
TS    technical specification(s)
UFSAR Updated Final Safety Analysis Report
URI  unresolved item
UT    ultrasonically testing
V/Hz  volt/hertz
VHRA  very high radiation areas
WGE  work group evaluation
WOs  work order(s)
}}
}}

Latest revision as of 14:57, 30 October 2019

Integrated Inspection Report 05000272/2016002 and 05000311/2016002
ML16266A224
Person / Time
Site: Salem  PSEG icon.png
Issue date: 09/22/2016
From: Fred Bower
Reactor Projects Branch 3
To: Sena P
Public Service Enterprise Group
References
IR 2016002
Download: ML16266A224 (66)
v • d • e


See also: IR 05000272/2016002

Text

T. Joyce

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION I

2100 RENAISSANCE BLVD., SUITE 100

KING OF PRUSSIA, PA 19406-2713

September 22, 2016

Mr. Peter Sena, III

President and Chief Nuclear Officer

PSEG Nuclear LLC - N09

P.O. Box 236

Hancocks Bridge, NJ 08038

SUBJECT: SALEM NUCLEAR GENERATING STATION, UNITS 1 AND 2 -

INTEGRATED INSPECTION REPORT 05000272/2016002 AND

05000311/2016002

Dear Mr. Sena:

On June 30, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at

the Salem Nuclear Generating Station, Units 1 and 2 (Salem). The enclosed inspection report

documents the inspection results, which were discussed with Mr. Robert DeNight on July 28,

2016, and with Mr. Eric Carr on August 11, 2016, as well as other members of your staff.

NRC Inspectors examined activities conducted under your license as they relate to safety and

compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed

personnel.

The inspectors documented two findings of very low safety significance (Green) in this report.

Further, inspectors documented a licensee-identified violation which was determined to be of

very low safety significance in this report. The NRC is treating these issues as one finding (FIN)

and as two non-cited violations (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the NCV in this report, you should provide a response within 30 days of the date

of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission,

ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional

Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory

Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Salem. In

addition, if you disagree with the cross-cutting aspect assigned to any finding, 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

Regional Administrator, Region I, and the NRC Resident Inspector at Salem.

P. Sena -2-

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs

Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be

available electronically for public inspection in the NRCs Public Document Room or from

the Publicly Available Records component of the NRCs Agencywide Documents Access and

Management System (ADAMS). ADAMS is accessible from the NRC website at

http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Fred L. Bower, III, Chief

Reactor Projects Branch 3

Division of Reactor Projects

Docket Nos. 50-272 and 50-311

License Nos. DPR-70 and DPR-75

Enclosure:

Inspection Report 05000272/2016002 and

05000311/2016002

w/Attachment: Supplementary Information

cc w/encl: Distribution via ListServ

ML16266A224

Non-Sensitive Publicly Available

SUNSI Review

Sensitive Non-Publicly Available

OFFICE RI/DRP RI/DRP RI/DRS RI/DRP RI/DRP

NAME PFinney/RB RBarkley MGray MScott FBower

DATE 9/16/16 9/14/16 9/16/16 9/22/16 9/22/16

1

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket Nos. 50-272 and 50-311

License Nos. DPR-70 and DPR-75

Report Nos. 05000272/2016002 and 05000311/2016002

Licensee: PSEG Nuclear LLC (PSEG)

Facility: Salem Nuclear Generating Station, Units 1 and 2

Location: P.O. Box 236

Hancocks Bridge, NJ 08038

Dates: April 1, 2016 through June 30, 2016

Inspectors: P. Finney, Senior Resident Inspector

A. Ziedonis, Resident Inspector

E. Burket, Emergency Preparedness Specialist

G. DiPaolo, Senior Reactor Inspector

M. Draxton, Project Engineer

J. Kulp, Senior Reactor Inspector

M. Modes, Senior Reactor Inspector

R. Nimitz, Senior Health Physicist

T. OHara, Reactor Engineer

D. Orr, Senior Reactor Inspector

R. Vadella, Project Engineer

J. Poehler, Senior Materials Engineer

Approved By: Fred L. Bower, III, Chief

Reactor Projects Branch 3

Division of Reactor Projects

Enclosure

2

TABLE OF CONTENTS

REPORT DETAILS ....................................................................................................................... 5

1. REACTOR SAFETY .............................................................................................................. 5

1R01 Adverse Weather Protection ...................................................................................... 5

1R04 Equipment Alignment .................................................................................................. 7

1R05 Fire Protection ............................................................................................................. 7

1R07 Heat Sink Performance .............................................................................................. 7

1R08 In-service Inspection Activities ................................................................................... 7

1R11 Licensed Operator Requalification Program ............................................................ 12

1R12 Maintenance Effectiveness ...................................................................................... 12

1R13 Maintenance Risk Assessments and Emergent Work Control ................................ 13

1R15 Operability Determinations and Functionality Assessments .................................... 14

1R18 Plant Modifications ................................................................................................... 19

1R19 Post-Maintenance Testing ....................................................................................... 20

1R20 Refueling and Other Outage Activities ...................................................................... 20

1R22 Surveillance Testing ................................................................................................. 21

1EP6 Drill Evaluation ........................................................................................................ 22

2. RADIATION SAFETY .......................................................................................................... 22

2RS1 Radiological Hazard Assessment and Exposure Controls ....................................... 22

2RS2 Occupational ALARA Planning and Controls ........................................................... 24

2RS3 In-Plant Airborne Radioactivity Control and Mitigation ............................................. 25

2RS4 Occupational Dose Assessment .............................................................................. 26

2RS5 Radiation Monitoring Instrumentation ...................................................................... 27

2RS7 Radiological Environmental Monitoring Program (REMP) ....................................... 28

4. OTHER ACTIVITIES............................................................................................................ 29

4OA1 Performance Indicator Verification ............................................................................ 29

4OA2 Problem Identification and Resolution ..................................................................... 29

4OA3 Follow-Up of Events and Notices of Enforcement Discretion.................................... 39

4OA5 Other Activities .......................................................................................................... 43

4OA6 Management Meetings ............................................................................................. 45

4OA7 Licensee-identified Violations ................................................................................... 45

ATTACHMENT: SUPPLEMENTARY INFORMATION ............................................................... 46

SUPPLEMENTARY INFORMATION ........................................................................................ A-1

KEY POINTS OF CONTACT .................................................................................................... A-1

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED ......................................................... A-2

LIST OF DOCUMENTS REVIEWED ........................................................................................ A-3

LIST OF ACRONYMS............................................................................................................. A-16

3

SUMMARY

Inspection Report (IR) 05000272/2016002, 05000311/2016002; 04/01/2016 - 06/30/2016;

Salem Nuclear Generating Station Units 1 and 2; Operability Determinations and Functionality

Assessments; Follow-Up of Events and Notices of Enforcement Discretion.

This report covered a three-month period of inspection by resident inspectors and announced

inspections performed by regional inspectors. The inspectors documented one self-revealing

finding of very low safety significance (Green), one non-cited violation (NCV), one finding (FIN)

and one licensee identified violation. The significance of most findings is indicated by their color

(i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection

Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated April 29, 2015.

Cross-cutting aspects are determined using IMC 0310, Aspects Within Cross-Cutting Areas,

dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance

with the NRCs Enforcement Policy, dated February 4, 2015. The NRCs program for

overseeing the safe operation of commercial nuclear power reactors is described in

NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.

Cornerstone: Mitigating Systems and Initiating Events

Green. The inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code

of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, "Instructions, Procedures,

and Drawings," because, from June 15, 2016 until July 26, 2016, PSEG did not accomplish

actions necessary to provide adequate confidence that a structure, system, and component

(SSC) would perform satisfactorily in service (an activity affecting quality) as prescribed by a

documented procedure. Specifically, although PSEG had concluded Salem Unit 2 is

susceptible to baffle bolt failure due to its design and operating life (but less susceptible than

Salem Unit 1), PSEG inadequately implemented Procedure OP-AA-108-115, "Operability

Determinations & Functionality Assessments," Sections 4.7.14 followed by Sections

4.7.18-4.7.20 to perform an operability evaluation (OpEval) to justify continued operation of

the unit until the next refueling outage. PSEGs immediate corrective actions included

entering the issue into its corrective action program (NOTF 20736630) and documenting an

operability evaluation to support the basis for functionality of the baffle structure and the

operability of the emergency core cooling system (ECCS) and reactivity control systems.

This finding is more than minor because it is associated with the equipment performance

attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to

ensure the availability, reliability, and capability of systems that respond to initiating events to

prevent undesirable consequences, in that degradation of a significant number of baffle bolts

could result in baffle plates dislodging following an accident. This issue was dispositioned as

more than minor because it was also similar to example 3.j of IMC 0612, Appendix E,

Examples of Minor Issues, in that the condition resulted in reasonable doubt of operability

of the ECCS and additional analysis was necessary to verify operability. In accordance with

IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A,

The Significance Determination Process for Findings At-Power, issued June 19, 2012, the

inspectors screened the finding for safety significance and determined it to be of very low

safety significance (Green), since the finding did not represent an actual loss of system or

function. After inspector questioning, PSEG performed OpEval 2016-015, which provided

sufficient bases to conclude the Unit 2 baffle assembly would support ECCS and control rod

system operability until the next refueling outage. This finding is related to the cross-cutting

4

aspect of Operating Experience because PSEG did not effectively evaluate relevant internal

and external operating experience. Specifically, PSEG did not adequately evaluate the

impact of degraded baffle bolts in Unit 2 when directly relevant operating experience was

identified at Unit 1. [P.5] (Section 1R15)

Green. A Green, self-revealing finding (FIN) was identified against MA-AA-716-010,

Maintenance Planning Process, Revision 18, when PSEG work orders (WOs) did not

specify the appropriate procedure to perform satisfactory modification testing of the main

generator automatic voltage regulator (AVR) protective relay (model STV1). Consequently,

the relay actuated below its design setpoint on February 4, 2016, resulting in an automatic

trip of the Unit 2 main turbine and reactor. PSEG entered the issue in their Corrective

Action Program (CAP) and performed a root cause evaluation (RCE), replaced the failed

STV1 relay with a properly tested relay, verified other STV relays were appropriately tested

as an extent of condition, and initiated an action to revise Laboratory Testing Services (LTS)

department relay test procedures to ensure all applicable acceptance criteria will be

incorporated.

The inspectors determined that a performance deficiency existed because PSEG WOs did

not specify the appropriate procedure to perform satisfactory modification testing of the main

generator AVR protection relay. This issue was more than minor since it was associated

with the procedure quality attribute of the Initiating Events cornerstone and adversely

impacted its objective to limit the likelihood of events that upset plant stability (turbine and

reactor trip) and challenge critical safety functions. Using IMC 0609, Attachment 4 and

Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety

significance, or Green, since mitigating equipment relied up to transition the plant to stable

shutdown remained available. The finding had a cross-cutting aspect in the area of Human

Performance, Work Management, in that the PSEG did not adequately implement the work

process to coordinate with engineering and maintenance departments as needed to

appropriately plan the STV1 relay modification test WO. [H.5] (Section 4OA3.3)

Other Findings

A violation of very low safety significance that was identified by PSEG was reviewed by the

inspectors. Corrective actions taken or planned by PSEG have been entered into PSEGs CAP.

This violation and corrective actions tracking number are listed in Section 4OA7 of this report.

5

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. The unit was shut down for a

refueling outage on April 14.

Unit 2 began the inspection period at 100 percent power. The unit remained at or near

100 percent power until June 28, when the unit tripped due to actuation of the main generator

protection system. The unit remained shut down at the end of the inspection period.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01 - 1 sample)

.1 Summer Readiness of Offsite and Alternate Alternating Current Power Systems

a. Inspection Scope

The inspectors reviewed plant features and procedures for the operation and continued

availability of the offsite and alternate alternating current (AC) power system to evaluate

readiness of the systems prior to seasonal high grid loading on May 31. The inspectors

reviewed PSEGs procedures affecting these areas and the communications protocols

between the transmission system operator and PSEG. This review focused on changes

to the established program and material condition of the offsite and alternate AC power

equipment. The inspectors assessed whether PSEG established and implemented

appropriate procedures and protocols to monitor and maintain availability and reliability

of both the offsite AC power system and the onsite alternate AC power system. The

inspectors evaluated the material condition of the associated equipment by interviewing

the responsible system manager, reviewing condition reports and open WOs, and

walking down portions of the offsite and AC power systems including the 500 kilovolt

(kV).

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial System Walkdown (71111.04Q - 4 samples)

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Unit 1, 1A and 1C 125V direct current (DC) system during 1B 125V DC battery

inoperability on April 6

Unit 1, Containment penetrations during irradiated fuel moves on April 19

6

Unit 2, Service water (SW) system during 21 SW pump emergent repairs on June 7

Unit 2, Auxiliary building ventilation with damper 2ABV2 failed open on June 16

The inspectors selected these systems based on their risk-significance relative to the

reactor safety cornerstones at the time they were inspected. The inspectors reviewed

applicable operating procedures, system diagrams, the Updated Final Safety Analysis

Report (UFSAR), technical specification(s) (TSs), WOs, notifications (NOTFs), and the

impact of ongoing work activities on redundant trains of equipment in order to identify

conditions that could have impacted the systems performance of its intended safety

functions. The inspectors also performed field walkdowns of accessible portions of the

systems to verify system components and support equipment were aligned correctly and

were operable. The inspectors examined the material condition of the components and

observed operating parameters of equipment to verify that there were no deficiencies.

The inspectors also reviewed whether PSEG staff had properly identified equipment

issues and entered them into the CAP for resolution with the appropriate significance

characterization.

b. Findings

No findings were identified.

.2 Full System Walkdown (71111.04S - 1 sample)

a. Inspection Scope

On June 22, 2016, the inspectors performed a complete system walkdown of accessible

portions of the Unit 2 safety injection (SI) to verify the existing equipment lineup was

correct. The inspectors reviewed operating procedures, surveillance tests, drawings,

equipment line-up check-off lists, and the UFSAR to verify the system was aligned to

perform its required safety functions. The inspectors also reviewed electrical power

availability, component lubrication and equipment cooling, hanger and support

functionality, and operability of support systems. The inspectors performed field

walkdowns of accessible portions of the systems to verify as-built system configuration

matched plant documentation, and that system components and support equipment

remained operable. The inspectors confirmed that systems and components were

aligned correctly, free from interference from temporary services or isolation boundaries,

environmentally qualified, and protected from external threats. The inspectors also

examined the material condition of the components for degradation and observed

operating parameters of equipment to verify that there were no deficiencies.

Additionally, the inspectors reviewed a sample of related notifications and WOs to

ensure PSEG appropriately evaluated and resolved any deficiencies.

b. Findings

No findings were identified.

7

1R05 Fire Protection

.1 Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material

condition and operational status of fire protection features. The inspectors verified that

PSEG controlled combustible materials and ignition sources in accordance with

administrative procedures. The inspectors verified that fire protection and suppression

equipment was available for use as specified in the area pre-fire plan, and passive fire

barriers were maintained in good material condition. The inspectors also verified that

station personnel implemented compensatory measures for out of service, degraded, or

inoperable fire protection equipment, as applicable, in accordance with procedures.

Unit 2, Spent fuel (SF) and component cooling heat exchangers (HXs) on May 12

Unit 2, Boric acid evaporator unit and chemistry area on May 20

Unit 2, SW pump bays during 21 SW pump maintenance on June 8

Unit 2, 2B and 2C emergency diesel generator (EDG) rooms on June 16

Unit 2, Chiller room while protected on June 16

b. Findings

No findings were identified.

1R07 Heat Sink Performance (711111.07A - 1 sample)

a. Inspection Scope

The inspectors reviewed the 12 SI pump lube oil cooler readiness and availability to

perform its safety functions. The inspectors reviewed the design basis for the

component and verified PSEGs commitments to NRC Generic Letter 89-13, Service

Water Requirements Affecting Safety-Related Equipment. The inspectors performed

inspection of the as-found conditions, and discussed the results of previous inspections

with PSEG staff. The inspectors verified that PSEG initiated appropriate corrective

actions for identified deficiencies. The inspectors also verified that the number of tubes

plugged within the HX did not exceed the maximum amount allowed.

b. Findings

No findings were identified.

1R08 In-service Inspection Activities (71111.08 - 1 sample)

a. Inspection Scope

Inspectors from the NRC Region I Office, specializing in materials and in-service

examination activities, observed portions of PSEGs activities involving baffle bolt

examinations and replacements during the Salem Unit 1 spring 2016 refueling outage

(1R24). PSEG notified the NRC of problems with baffle bolts in Event

8

Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel

Internals. During May 17-19, 2016, and June 20-23, 2016, inspectors conducted an

inspection of PSEGs evaluation of the baffle bolt ultrasonic testing results and visual

examination performed during 1R24. The inspectors reviewed documentation,

interviewed personnel, and reviewed video recordings of visual examinations performed

during the current and previous refueling outages. The inspectors also observed in-

progress baffle bolt replacement activities.

Nondestructive Examination and Welding Activities (Section 02.01)

The inspectors conducted a review of PSEGs implementation of in-service inspection

(ISI) program activities for monitoring degradation of the reactor coolant system

boundary, risk significant piping and components, and containment systems during

Salem Unit 1 refueling outage 1R24. The sample selection was based on the inspection

procedure objectives and risk priority of those pressure retaining components in these

systems where degradation would result in a significant increase in risk. The inspectors

observed in-process nondestructive examination (NDE), reviewed records, and

interviewed personnel to verify the following: a) that non-destructive activities were

performed in accordance with American Society of Mechanical Engineers (ASME) Boiler

and Pressure Vessel Code Section XI, 2004 Edition, no Addenda, requirements; b) that

indications and defects, if present, were dispositioned in accordance with the ASME

Code or an NRC approved alternative; and, c) that relevant indications were compared

to previous examinations to determine if any changes occurred.

The inspectors reviewed the ultrasonic testing (UT) procedure used for the examination

of the Unit 1 baffle bolts to verify it met the requirements of the ASME Boiler and

Pressure Vessel Code and the applicable guidance in the Electric Power Research

Institutes Materials Reliability Program (MRP-227 and 228). The inspectors reviewed

the UT data records for the examinations performed during the 1R24 refueling outage to

verify that activities were performed in accordance with applicable examination

procedures.

The inspectors reviewed video from the visual examination of the baffle bolts performed

in the current refueling outage (RFO). The inspectors also reviewed video of visual

examinations performed during Unit 1 RFOs in 2001, 2013, and 2014 to assess the

as-found conditions of the baffle bolts. The inspectors reviewed certifications of the NDE

technicians performing the examinations to verify the examinations were performed by

qualified individuals in accordance with approved procedures and the results reviewed

and evaluated by certified Level III NDE personnel.

The inspectors performed a sample of observations of NDE activities and reviewed

records of NDE activities. The review sample consisted of two or three types of NDE

activities, including at least one volumetric examination.

ASME Code Required Examinations

Salem Unit 1, Liquid Penetrant Report No. PT-16-002, 11-RHRHEX Vessel Support,

4/15/16, (Summary No.205170) [record review]

Salem Unit 1, Liquid Penetrant Report No. PT-16-001, Pipe Lugs 8-RH-2116-10PL-1

through 4, 4/15/16, (Summary No. 263631) [record review]

9

Salem Unit 1, Liquid Penetrant Report No. PT-16-004, Pipe to Penetration IA,

Component 12 SJ-2152-36PS-4, 4/19/16, (Summary No. 263904) [record review]

Salem Unit 1, Liquid Penetrant Report No. PT-16-003, Inlet Nozzle To 11

Charging Pump, Component 6-CV-2111-14R1, 4/15/16,

(Summary No. 220757) [record review]

Salem Unit 1, Liquid Penetrant Report No. PT-16-005, Pipe-to-Valve (11CS48)

[record review] Component ID: 8-CS-2114-60, 4/15/16, (Summary No. 56640)

Salem Unit 1, Ultrasonic examination (Summary #006325) Report UT-16-039,

Component ID: 1-PZR-20, Pressurizer, shell J weld [Observed]

Component ID: 16-BFN-2111-IRS, Inside Radius Section Ultrasonic

Examination, 16-BF-2111, Report UT-16-013, Steam Generator #11,

(Summary #204201) [Observed]

Component 4-PRN-1100-IRS, Pressurizer Relief Nozzle, inside Radius Section,

Ultrasonic Examination, (Summary #007000), UT-16-031, [Observed]

Observation of Baffle Bolt Replacement Activities

The inspectors observed electrical discharge machining activities on a baffle bolt

location. The inspectors observed the bolt hole milling activities for a baffle bolt. The

inspectors verified that bolt replacement activities were being performed in accordance

with approved procedures.

Other Augmented, License Renewal or Industry Initiative Examinations

PSEG did not schedule augmented inspections in the outage scope for 1R24.

Review of Relevant Indication(s) Evaluated and Accepted for Continued Service

PSEG did not have any originally rejectable indications since the end of their prior

outage, which were later accepted for continued use after evaluation.

Modifications, Repairs, or Replacements Consisting of Welding on Pressure Boundary

Risk Significant Systems

The inspectors reviewed Design Change Package 80092579, Salem Unit 1 - Steam

Generator (SG) Bowl Drain Repair, for SGs 11, 12, 13, and 14. This change removed

Alloy 600 and associated 82/182 weld material from each SG channel head bowl drain

plug to reduce the potential for primary water stress corrosion cracking. The inspectors

determined overall whether the modifications were completed in accordance with ASME

Section XI as a repair/replacement activity. Specifically, the inspectors reviewed the

machining and welding procedures used to complete the modifications, reviewed the

training of the machinists, welders and laborers qualified on a mockup of the channel

heads, and reviewed the mockup training completed by all craft personnel on the project.

The inspectors reviewed the in-process NDE and the final NDE procedures to determine

whether the change was implemented in accordance with ASME Section XI

repair/replacement requirements.

10

PWR Vessel Upper Head Penetration Inspection Activities (Section 02.02)

The Salem Unit 1 reactor pressure vessel head was replaced with an Alloy 690 head in

2005. The inspectors determined that reactor pressure vessel head examinations (per

ASME Code Case N-729) were not required during 1R24.

Boric Acid Corrosion Control Inspection Activities (Section 02.03)

The inspectors reviewed the Boric Acid Corrosion Control program and implementing

PSEG procedures, and discussed the outage inspections with program engineers. The

inspectors also reviewed documentation, corrective action process notifications,

including photographic records, of the conditions identified during the plant shutdown.

The inspectors also reviewed a sample of notifications recommending repairs to

identified conditions and a sample of boric acid engineering evaluations performed to

determine the priority of repair of identified boric acid corrosion on safety significant

piping and components. Boric acid inspections were conducted on safety significant

piping and components inside the containment structure during walk downs conducted

by PSEG staff with the plant at normal pressure and temperature conditions. The

inspectors reviewed a sample of photos and visual inspection records to verify that boric

acid leakage was being appropriately identified and non-conforming conditions of boric

acid leaks were documented in the CAP with a focus on areas that could cause

degradation of safety significant components.

The inspectors verified that potentially more significant boric acid deficiencies were

being adequately dispositioned by reviewing a sample of evaluations documented in the

following PSEG condition reports: 20682192, 20699859, 20699820, 20699910,

20704139, 20707125, 20712774, 20713572, 20722494, 20682192, 20699859,

20707125, 20722494, 70179375, 20699820, 20704139, 70185980, 20712774,

20713573, 20713572.

These reviews verified whether the corrective actions were consistent with the

requirements of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI. The

inspectors reviewed the engineering evaluations associated with these condition reports

to verify whether equipment or components wetted or impinged upon by boric acid

solutions were properly analyzed for degradation that might impact their function.

Steam Generator Tube Inspection Activities (Section 02.04)

PSEGs Base Eddy Current Test (ECT) program consisted of: (a) 100 percent bobbin

probe inspection of straight and U-bend tubes, (b) 50 percent Hot Leg coverage of Top

of Tubesheet area with an array probe, (c) 3 tube periphery tube array testing, and

various + Point sampling strategies (for U-bend and Dent/Ding inspections) of in-service

tubes were completed in each SG. The inspectors reviewed the 1R24 SG tube

Degradation Assessment, ECT examination scope and expansion criteria to verify that it

met TS requirements, Electric Power Research Institute (EPRI) guidelines, and

commitments made to the NRC. The inspectors also verified that the ECT scope

included areas of degradation that were known to represent potential ECT challenges

such as the top of tube sheet, tube support plates, and U-bends. Upon completion of

eddy current (EC) examinations and the evaluation of all data, PSEG staff determined

that six tubes required plugging. The affected tubes were plugged during 1R24. The

11

inspectors verified that the affected tubes were properly screened against the in situ

screening criteria and that none of the tube indications required in-situ pressure testing.

The inspectors observed portions of the ECT being performed and verified whether:

(1) the appropriate probes were used for identifying the expected types of degradation,

(2) calibration requirements were adhered to, and (3) probe travel speed was in

accordance with procedural requirements. The inspectors performed a review of the

site-specific qualifications for the techniques being used, and verified whether the ECT

data analyses were adequately performed per EPRI and PSEG specific guidelines. The

inspectors selected a sample of degraded tubes and compared them to the previous

outage operational assessment to assess PSEGs prediction capabilities. The inspectors

also reviewed a sample of EC data, and verified, through discussion with the data

analyst that the analytical techniques used to evaluate the inspection data were

adequate. The inspectors further verified that the assumed NDE flaw sizing accuracy

was consistent with data from EPRI examination technique specification sheet or

applicable performance demonstration. Finally, the inspectors reviewed the

qualifications for the EC data collection personnel, a sample of the inspection

supervision personnel qualifications and a sample of the qualifications of staff

responsible for interpretation and resolution analysis to determine whether the records

were complete.

The inspectors observed a portion of a plug integrity visual examination per procedure

81DP-9RC40, Steam Generator Channel Head Video Inspection, to verify that those

tubes that had been previously plugged did not exhibit any leakage. No evidence of plug

leakage was identified. Additionally, the inspectors observed a portion of the secondary

sludge lancing and foreign object search and retrieval (FOSAR) inspections. No

significant foreign materials or quantity of sludge were identified.

During the prior operating cycle previous to the current refueling outage 1R24, the

inspectors determined whether leakage from each SG was measured, via sampling of

each SG, for the complete prior operating cycle (leakage was not measured).

PSEG staff completed secondary side inspections and sludge lancing of all SGs. The

inspectors reviewed the results to determine that no loose parts affecting tube integrity

were noted and that other SG related inspections were performed without repairs.

PSEG staff performed a plug integrity visual examination to verify that those tubes that

had been previously plugged did not exhibit leakage. From this visual exam, PSEG staff

documented excessive boron buildup around tube plug 43-34 in the SG 11 cold leg and

initiated CR-2016-29172 to track the evaluation of the condition. PSEG staff also

initiated Notification 20726743 to track the condition. PSEG Engineering staff review of

the plug concluded that no evidence of plug leakage had occurred. Additionally,

secondary sludge lancing and FOSAR inspections were performed in each SG. No

foreign materials, which could damage SG tubes, were identified. The inspectors

reviewed the PSEG evaluations and information to determine the conclusions were

technically supported.

Identification and Resolution of Problems (Section 02.05)

The inspectors reviewed a sample of condition reports, which identified NDE indications,

deficiencies and other nonconforming conditions since the previous, 1R23, refueling

outage. The inspectors verified that nonconforming conditions were properly identified,

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characterized, evaluated, corrective actions identified and dispositioned, and

appropriately entered into the CAP.

b. Findings

Introduction. The inspectors determined the level of degradation of Unit 1 baffle bolts

reported to the NRC as a condition not previously analyzed is an issue of concern that

warrants additional inspection to determine whether a performance deficiency exists. As

a result, the NRC opened a unresolved item (URI).

Description. Additional inspection is warranted to determine whether a performance

deficiency exists related to Event Notification 51902, dated May 3, 2016, in which PSEG

reported to the NRC that the level of degradation of baffle bolts was a condition not

previously analyzed. The baffle bolts secure plates in the reactor core barrel to form a

shroud around the fuel core to direct reactor coolant flow upward through the fuel

assemblies. In order to determine if a performance deficiency exists, the inspectors will

review the results of PSEGs RCE which will be completed at a later date.

(URI 05000272/2016002-01, Baffle-Former Bolts with Identified Anomalies)

1R11 Licensed Operator Requalification Program (71111.11Q - 1 sample)

Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on June 8, 2016, which

included a heater drain pump oil leak, a steam generator feed pump trip, and a steam

generator tube rupture. The inspectors evaluated operator performance during the

simulated event and verified completion of risk significant operator actions, including the

use of abnormal and emergency operating procedures. The inspectors assessed the

clarity and effectiveness of communications, implementation of actions in response to

alarms and degrading plant conditions, and the oversight and direction provided by the

control room supervisor. The inspectors verified the accuracy and timeliness of the

emergency classification made by the shift manager and the TS action statements

entered by the shift technical advisor. Additionally, the inspectors assessed the ability of

the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness (71111.12Q - 3 samples)

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of

maintenance activities on SSC performance and reliability. The inspectors reviewed

system health reports, CAP documents, maintenance WOs, and maintenance rule (MR)

basis documents to ensure that PSEG was identifying and properly evaluating

performance problems within the scope of the MR. For each sample selected, the

inspectors verified that the SSC was properly scoped into the MR in accordance with

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10 CFR 50.65 and verified that the (a)(2) performance criteria established by PSEG staff

was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed

the adequacy of goals and corrective actions to return these SSCs to (a)(2).

Additionally, the inspectors ensured that PSEG staff was identifying and addressing

common cause failures that occurred within and across MR system boundaries.

Unit 2, 22SW535, unsatisfactory stroke time of SW accumulator supply valve to

22 containment fan cooler unit (CFCU) on May 2

Unit 2, Circulating water system 125V DC battery degradation on May 23

Common, MR URI, 05000272;311/2015008-01: Inadequate MR System

Performance Criteria Selection, closeout on May 1

b. Findings

No findings were identified. Additional inspection results regarding the URI closeout are

documented in Section 4OA5.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 5 samples)

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the

maintenance and emergent work activities listed below to verify that PSEG performed

the appropriate risk assessments prior to removing equipment for work. The inspectors

selected these activities based on potential risk significance relative to the reactor safety

cornerstones. As applicable for each activity, the inspectors verified that PSEG

personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the

assessments were accurate and complete. When PSEG performed emergent work, the

inspectors verified that operations personnel promptly assessed and managed plant risk.

The inspectors reviewed the scope of maintenance work and discussed the results of

the assessment with the stations probabilistic risk analyst to verify plant conditions were

consistent with the risk assessment. The inspectors also reviewed the TS requirements

and inspected portions of redundant safety systems, when applicable, to verify risk

analysis assumptions were valid and applicable requirements were met.

Unit 1, 11SW223, SW outlet valve to 11 CFCU, failure to close on April 7

Unit 1, Reactor core baffle-to-former bolt expanded inspection scope on April 22

Unit 2, Appendix R safe shutdown panel failed indication on May 9

Unit 2, 2A subcooling margin monitor failure on May 26

Unit 2, Yellow risk with one offsite power source unavailable on June 1

b. Findings

No findings were identified.

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1R15 Operability Determinations and Functionality Assessments (71111.15 - 9 samples)

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or

non-conforming conditions based on the risk significance of the associated components

and systems:

Unit 1, Corrosion and metal loss identified during inspection of 11 SW header

on April 23

Unit 1, Immediate operability determination (IOD) of the degraded condition of the

baffle-former bolts on April 27

Unit 1, 1 Emergency control air compressor shutdown on April 27

Unit 1, SI thermal relief valve failures on May 2

Unit 1, 13 turbine-driven auxiliary feedwater (AFW) pump degraded performance

on May 8

Unit 1, 11 diesel fuel oil storage tank high particulates on May 18

Unit 2, IOD of the degraded condition of the baffle-former bolts identified from Unit 1

operating experience on April 27

Unit 2, 125V DC battery degraded cell post connections on May 2

Common, 10 CFR Part 21 issue related to safety-related 4kV breakers on May 16

The inspectors evaluated the technical adequacy of the operability determinations to

assess whether TS operability was properly justified and the subject component or

system remained available such that no unrecognized increase in risk occurred. The

inspectors compared the operability and design criteria in the appropriate sections of the

TSs and UFSAR to PSEGs evaluations to determine whether the components or

systems were operable. The inspectors confirmed, where appropriate, compliance with

bounding limitations associated with the evaluations. Where compensatory measures

were required to maintain operability, the inspectors determined whether the measures

in place would function as intended and were properly controlled by PSEG.

b. Findings

Introduction. The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B,

Criterion V, "Instructions, Procedures, and Drawings," because, from June 15, 2016

until July 26, 2016, PSEG did not accomplish actions necessary to provide adequate

confidence that an SSC would perform satisfactorily in service (an activity affecting

quality) as prescribed by a documented procedure. Specifically, although PSEG had

concluded Salem Unit 2 is susceptible to baffle bolt failure due to its design and

operating life (but less susceptible than Salem Unit 1), PSEG inadequately implemented

Procedure OP-AA-108-115, "Operability Determinations & Functionality Assessments,"

by not performing Section 4.7.14 followed by Sections 4.7.18-4.7.20 to perform an

operability evaluation (OpEval) to justify continued operation of the unit until the next

refueling outage. In particular, PSEG incorrectly exited their procedure on June 15,

2016, and re-entered it to complete these steps on July 26, 2016, based on discussions

with the NRC. The operability evaluation provided appropriate justification for the

licensees plans to examine the baffle-former bolts at the next Unit 2 RFO.

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Description. On April 22, 2016, PSEG identified baffle-former (baffle) bolt degradation

at Salem Unit 1 that was determined to be unanalyzed because it did not meet the

minimum acceptable bolt pattern analysis developed to support plant startup. PSEG

staff identified that 192 baffle bolts out of a total population of 832 were considered

degraded. On May 4, 2016, due to the number of degraded baffle bolts discovered on

Unit 1, PSEG staff determined that it was necessary to perform an extent of condition

review for the baffle bolts on Unit 2. PSEG entered this issue into the corrective action

program as NOTF 20727590 and completed an immediate operability determination

(IOD) to evaluate the Unit 2 baffle bolts and baffle assembly structure in accordance with

PSEG procedure OP-AA-108-115, "Operability Determinations & Functionality

Assessments," Section 4.7.4.

The inspectors reviewed the design basis and current licensing basis documents for

Unit 2 to identify the specific safety functions of the baffle bolts. The inspectors identified

that the baffle bolts are part of the baffle assembly structure located in the reactor

pressure vessel. The bolts secure a series of vertical metal plates called baffle plates,

which help direct water up through the nuclear fuel assemblies to ensure proper cooling

of the fuel. A sufficient number of baffle bolts are required to secure the plates to ensure

proper core flow during normal and postulated accident conditions, and also to ensure

that control rods can be inserted to shut down the reactor.

On June 21, 2016, the inspectors reviewed the IOD as part of a detailed review of the

ongoing baffle bolt activities at Salem and noted that the IOD concluded that there was

reasonable assurance that the Unit 2 reactor assembly was operable, but required

additional evaluation due to the conditions observed in Unit 1. Specifically, the IOD

concluded that there was reasonable assurance that the Unit 2 reactor assembly was

operable pending further evaluation based upon the following factors: (1) Unit 2 had

fewer effective full power years of operation than Unit 1; (2) a baffle bolt visual

examination completed during the most recent Unit 2 2R21 refueling outage (fall 2015)

did not identify any visual deficiencies; and, (3) there was no current indication of reactor

fuel pin leakage in Unit 2, which could be caused by baffle bolt failure and subsequent

fretting. The inspectors review of PSEGs IOD concluded that the IOD provided

sufficient technical detail to support the initial conclusion that there was reasonable

assurance, based on the limited information available, that the Unit 2 baffle bolts would

retain sufficient capability to perform their intended functions. PSEG procedure OP-AA-

108-115, Section 4.7.11 directs that if there is a reasonable expectation that the SSC is

operable, but a more rigorous evaluation is deemed warranted, then update the current

notification or initiate a notification for Engineering to prepare a Technical Evaluation to

support the prompt determination of operability. The immediate actions section of

NOTF 20727590 requested a work order be generated to perform an extent of condition

review for Unit 2 baffle bolts. The Station Ownership Committee (SOC) screening of

NOTF 20727590 on May 6, 2016, assigned a work order to Engineering to ensure that

Operations is provided the Technical Evaluation product. This will allow review for

assessment of operability as required. From review of the daily running log of baffle

bolt action items spreadsheet, the inspectors noted that on May 4, 2016, action EOC.2

to perform an operability evaluation for Unit 2 was closed to EOC.7-9, to complete an

adverse condition monitoring plan, an operational decision making document, and a

Technical Evaluation in lieu of an OpEval. Consistent with this decision, on May 26,

2016, the Salem plant manager discussed with the senior resident inspector PSEGs

views that an operability evaluation was not required or being developed. In response,

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the inspectors shared their understanding of PSEG procedure guidance and regulatory

requirements in this regard.

Between May 6 and June 15, 2016, PSEG engineering performed Technical Evaluation

70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt

Failure. The purpose of the Technical Evaluation was to determine the potential for

baffle bolt degradation in Unit 2 based upon the results of visual and ultrasonic

examination results observed in Unit 1, and to identify and evaluate key factors that

could potentially impact the safe operation of Unit 2 for the remainder of the current

operating cycle. The Technical Evaluation evaluated the key factors that affect

irradiation assisted stress corrosion cracking (IASCC). Additionally, the Technical

Evaluation assessed the safety consequences of the degraded baffle bolts in the as-

found condition in Unit 1. The Technical Evaluation conclusion summary indicated that

Unit 2 is susceptible to baffle bolt failure due to its design and operating life; that any

degradation in Unit 2 would be less advanced that that observed in Unit 1; and that

PSEG should exercise heightened awareness and monitoring of Unit 2 due to this

vulnerability. The Technical Evaluation also concluded that Unit 1 could have safely

shut down and the core would be cooled by demonstrating that control rod insertability is

assured and a core coolable geometry was maintained. Thus the Technical Evaluation

concluded that Unit 2 could also be shut down and cooled based upon the conclusion

reached regarding Unit 1. Following completion of the Technical Evaluation on June 15,

PSEG did not continue on in the operability determination process.

The inspectors assessed PSEGs Technical Evaluation 70187161 during an onsite

inspection which took place from June 21-23, 2016. PSEG concluded in Technical

Evaluation 70187161, that Salem Unit 2 is susceptible to baffle bolt failure due to its

design and operating history, but less so than observed in Salem Unit 1. The inspectors

determined this conclusion met PSEGs definition of a degraded condition as defined in

procedure OP-AA-115-108, Section 2.4. Section 2.4 defines a degraded condition as A

condition in which the qualification of an SSC or its functional capability is reduced.

Section 2.4 lists reduced reliability as an example of a degraded condition and aging

as an example of a condition that can reduce the capability of a system. The inspectors

noted that IASCC is a time dependent aging degradation mechanism and baffle bolt

failures reduce the functional capability and reliability of the baffle assembly.

Consequently the Technical Evaluation describes a degraded condition in the Unit 2

baffle assembly. Since the Technical Evaluation concluded that the reactor could be

shut down and cooled based upon the assessment of safety consequences, the

inspectors concluded that PSEG considered that the reactivity control and emergency

core cooling systems were operable. As a result, the inspectors concluded that PSEG

should have continued on in the operability determination process as described in

Section 4.7.14, Operable but Degraded or Nonconforming, and declared both the

reactivity control and emergency core cooling systems operable but degraded. Once a

SSC is determined to be operable but degraded, Section 4.7.18 directs that An

OpEval will be requested based on a declaration of operable but degraded or

nonconforming. Section 4.7.19 directs Engineering to Prepare and review and

OpEval. Section 4.7.20 directs Operations to approve or disapprove the OpEval when

Engineering completes it. Sections 4.7.14, 4.7.18, 4.7.19 and 4.7.20 were not

implemented by PSEG.

The inspectors acknowledged that licensees apply judgment in these decisions and can

use a graded approach regarding the level of detail. In this particular instance, the

17

inspectors considered that operating experience was available that showed the Unit 2

baffle bolts were subject to IASCC and that plants of similar design (4-loop

Westinghouse pressurized water reactors with a down-flow configuration and baffle bolts

of 347 stainless steel material and similar dimensions) were subject to greater amounts

of bolt degradation compared to other reactor designs. Furthermore, the inspectors

noted the baffle bolts had experienced levels of neutron radiation exposure above the

threshold for IASCC initiation as referenced in NUREG/CR-7027, Degradation of LWR

Core Internal Materials due to Neutron Irradiation.

The inspectors conducted an exit meeting on June 23, 2016, describing a potential

violation of 10 CFR Part 50 Appendix B, Criterion 5, Instructions, Procedures, and

Drawings, for PSEG not completing the OpEval and assessing the effect of the

operability of the ECCS and rod control system based upon the functionality of the baffle

former assembly. Consistent with the change made by PSEG staff to the Salem action

item list on May 4, 2016, to not perform an OpEval, the PSEG Compliance Director

indicated that an operability evaluation was not required and therefore they disagreed

with this finding.

The inspectors determined that Engineering did not perform an OpEval as directed by

OP-AA-108-115 Section 4.7.19, which states PREPARE and REVIEW an OpEval. The

OpEval Form (Attachment 1), or a facsimile, may be used to document the engineering

evaluation (Engineering). Because an OpEval was not prepared, Operations did not

have the opportunity to approve or disapprove an OpEval as required by

OP-AA-108.115, Section 4.7.20 which states: When Engineering completes the

OpEval, then APPROVE or DISAPPROVE.

In summary, Technical Evaluation 70187161 concluded Unit 2 is susceptible to IASCC

baffle bolt degradation and that the expected degradation should be less than that

observed in Unit 1. The inspectors assessed that PSEGs conclusions concerning the

susceptibility and expected degradation in Unit 2 was adequately supported. However,

the inspectors concluded that the Technical Evaluation did not provide adequate

confidence that SSCs (baffle bolts supporting ECCS) would perform satisfactorily in

service to justify continued operation of Unit 2 until the next refueling outage in the

spring of 2017 in that line break size assumptions were not adequately supported.

Following discussions with NRC Region I management and the inspectors, PSEG staff

subsequently completed an operability evaluation (OpEval 2016-015) on July 26, 2016.

The OpEval compared the differences in the operating history and parameters between

Unit 1 and Unit 2 and again concluded that Unit 2 was less susceptible than Unit 1

primarily due to significantly fewer thermal cycles and fewer effective full power years

(EFPY) of operation. The OpEval concluded that operability was supported although

the Unit 2 baffle assemblies are considered degraded since Unit 2 is susceptible to

degraded baffle bolts. Based upon a qualitative analysis, PSEGs OpEval stated that

Unit 2 can accommodate 38 percent degraded baffled-former bolts (distributed across

the assembly) and remain within the acceptable bolting pattern analysis patterns

assuming the dynamic loads of a large break loss of coolant accident. The inspectors

concluded that PSEGs OpEval 2016-015 provided an adequate basis to conclude that

the Unit 2 baffle assembly would support ECCS and rod control system continued

operation until the planned refueling outage in spring 2017. In particular, the inspectors

considered that PSEGs visual examinations of approximately 70 percent of the baffle

bolts, in the fall 2015 refueling outage (2R21), did not identify any bolts that were

18

missing or visually degraded. Considering the collective results from Salem Unit 1 and 2

baffle bolt visual examination results, the inspectors determined this evidence, in

conjunction with a review of other operating factors (EFPY and thermal cycles), provided

a reasonable expectation of the Salem Unit 2 baffle assemblys capability to perform its

supporting TS functions.

Analysis. The inspectors determined that a performance deficiency resulted when PSEG

did not implement Procedure OP-AA-108-115, "Operability Determinations &

Functionality Assessments," Section 4.7.14 followed by Sections 4.7.18-4.7.20 to

perform an OpEval to justify continued operation of the unit until the next refueling

outage for the Unit 2 baffle bolt degraded condition until questioned by NRC inspectors.

PSEGs initial documentation did not provide sufficient basis for continued operation until

the next refueling outage. Specifically, based upon the Technical Evaluation 70187161

conclusion that the Salem Unit 2 design and operating life make it susceptible to baffle

bolt failures, the inspectors determined that PSEG, in effect, concluded that a degraded

condition exists in Unit 2. Therefore, PSEG should have continued on in the operability

determination process as described in Section 4.7.14, Operable but Degraded or

Nonconforming.

This finding is more than minor because it is associated with the equipment performance

attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to

ensure the availability, reliability, and capability of systems that respond to initiating

events to prevent undesirable consequences, in that, degradation of a significant

number of baffle bolts could result in baffle plates dislodging following an accident. This

issue was dispositioned as more than minor because it was also similar to example 3.j of

IMC 0612, Appendix E, Examples of Minor Issues, in that, the condition resulted in

reasonable doubt of operability of the ECCS and additional analysis was necessary to

verify operability. In accordance with IMC 0609.04, Initial Characterization of Findings,

and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for

Findings At-Power, issued June 19, 2012, the inspectors screened the finding for safety

significance and determined it to be of very low safety significance (Green), since the

finding did not represent an actual loss of system or function. After inspector

questioning, PSEG performed OpEval 2016-015, which provided sufficient bases to

conclude the Unit 2 baffle assembly would support ECCS and control rod system

operability until the next RFO. This finding is related to the cross-cutting aspect of

Operating Experience because PSEG did not effectively evaluate relevant internal and

external operating experience. Specifically, PSEG did not adequately evaluate the

impact of degraded baffle bolts at Unit 2 when directly relevant operating experience

was identified at Unit 1. [P.5]

Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and

Drawings, states, in part, that activities affecting quality shall be prescribed by

documented procedures of a type appropriate to the circumstances and shall be

accomplished in accordance with those procedures. The Introduction to Appendix B

states that quality assurance comprises all those planned and systematic actions

necessary to provide adequate confidence that a SSC will perform satisfactorily in

service. PSEG Procedure OP-AA-108-115, "Operability Determinations & Functionality

Assessments," prescribes PSEGs process to assess the operability of SSCs that are

required to be operable by TSs, or that perform required support functions for SSCs that

are required to be operable by TSs. Section 4.7 prescribes the operability determination

process. Section 4.7.14 states that if an SSC described in TSs is determined to be

19

operable even though a degraded or nonconforming condition is present, then the SSC

is considered operable but degraded or nonconforming. Sections 4.7.18 - 4.7.20

describe how the Operations Shift Manager should request the site engineering staff to

perform an OpEval upon a declaration of operable but degraded, or nonconforming.

The OpEval is completed to justify continued operation during the period of time while

operable but degraded or nonconforming conditions exist.

Contrary to the above, from June 15, 2016, until July 26, 2016, PSEG did not

accomplish actions necessary to provide adequate confidence that an SSC would

perform satisfactorily in service (an activity affecting quality) as prescribed by a

documented procedure. Specifically, although PSEG had concluded the Salem Unit 2

design and operating life make it susceptible to baffle former bolt failures, PSEG

inadequately implemented Procedure OP-AA-108-115, to perform an OpEval to justify

continued operation of the unit. PSEGs corrective actions included entering the issue

into its corrective action program (NOTF 20736630) and documenting an adequate

operability evaluation (OpEval 2016-015 on July 26, 2016) to support the basis for

functionality of the baffle structure and its ability to support the operability of the ECCS

and reactivity control systems. This violation is being treated as an NCV, consistent with

Section 2.3.2 of the Enforcement Policy. (NCV 05000311/2016002-02, Failure to

Follow Operability Determination Procedure for Unit 2 Baffle-Former Bolts)

1R18 Plant Modifications (71111.18 - 2 samples)

.2 Permanent Modifications

a. Inspection Scope

The inspectors reviewed Design Change Package (DCP) 80117136, Salem Unit 1

Baffle to Former Bolt Replacement. This modification documents the replacement of

189 degraded and potentially degraded baffle bolts with a new design baffle bolt made of

an improved material. Additionally the modification documented the locations of the

replacement bolts and the location of three degraded or potentially degraded bolts which

were left in place and are described below. The inspectors also reviewed modification

documents (DCP 80117378) associated with the equivalency evaluation of the material

change from Type 347 stainless steel to Type 316 stainless steel, and the bolt head

design change from a slot to a hex configuration. Thus this inspection involved two

samples - 1) the bolting pattern analysis for the replacement bolts, and 2) a review of

the bolting material change.

This modification was completed during the spring 2016 refueling outage (1R24) and

involved the replacement of 189 baffle bolts out of a total of 832 located in the Unit 1

reactor vessel. PSEG replaced 189 either degraded or potentially degraded baffle bolts

as observed by visual indications of missing or protruding bolt heads, missing or broken

lock bar, bolts that did not pass ultrasonic testing or bolts that were inaccessible for

ultrasonic testing. PSEG did not remove and replace three bolts that were potentially

degraded due to difficulties encountered during the removal/replacement process. One

bolt had an indication during ultrasonic testing but was not visibly damaged. The second

bolt was inaccessible for ultrasonic testing, which would have required replacement.

The third bolt had successfully passed an ultrasonic test but had a visual indication on

one of the lock bar welds which may have indicated a crack in the weld.

20

The inspectors reviewed PSEGs analysis and the Westinghouse minimum bolting

analysis and determined that leaving the one degraded and two potentially degraded

bolts installed was technically acceptable and that the baffle assembly was functional as

a system support component. Details of the NRC assessment of the final configuration

of the baffle bolts and the minimum bolting analysis can be found in Section 4OA2 of this

report.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing (71111.19 - 9 samples)

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed

below to verify that procedures and test activities adequately tested the safety functions

that may have been affected by the maintenance activity, that the acceptance criteria in

the procedure were consistent with the information in the applicable licensing basis

and/or design basis documents, and that the test results were properly reviewed and

accepted and problems were appropriately documented. The inspectors also walked

down the affected job site, observed the pre-job brief and post-job critique where

possible, confirmed work site cleanliness was maintained, and witnessed the test or

reviewed test data to verify quality control hold point were performed and checked,

and that results adequately demonstrated restoration of the affected safety functions.

Unit 1, 13 Station power transformer tap changer did not function in automatic on

May 4

Unit 1 11SJ45, residual heat removal (RHR) to SI motor-operated valve failure to

stroke closed on May 5

Unit 1, 12 containment fan cooling unit (CFCU) motor cooler HX failed leak test on

May 6

Unit 1, Reactor coolant pump flow channel III degraded on May 6

Unit 1, Turbine-driven AFW room cooler cycling on May 10

Unit 1, Reactor vessel level indication system capillary repair on May 13

Unit 2, 24 SW strainer trip on thermal overloads on April 7

Unit 2, 24 SG flow channel 1 drop to 93 percent on May 4

Unit 2, 21 Chiller thermal expansion valve failure on May 24

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities (71111.20 - 1 sample)

a. Inspection Scope

The inspectors reviewed the stations work schedule and outage risk plan for the Unit 1

maintenance and refueling outage (1R24), conducted April 14 through the end of the

quarter. The inspectors reviewed PSEGs development and implementation of outage

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plans and schedules to verify that risk, industry experience, previous site-specific

problems, and defense-in-depth were considered. During the outage, the inspectors

observed portions of the shutdown and cooldown processes and monitored controls

associated with the following outage activities:

Configuration management, including maintenance of defense-in-depth,

commensurate with the outage plan for the key safety functions and compliance with

the applicable TSs when taking equipment out of service

Implementation of clearance activities and confirmation that tags were properly hung

and that equipment was appropriately configured to safely support the associated

work or testing

Installation and configuration of reactor coolant pressure, level, and temperature

instruments to provide accurate indication and instrument error accounting

Status and configuration of electrical systems and switchyard activities to ensure that

TSs were met

Monitoring of decay heat removal operations

Impact of outage work on the ability of the operators to operate the SF pool cooling

system

Reactor water inventory controls, including flow paths, configurations, alternative

means for inventory additions, and controls to prevent inventory loss

Activities that could affect reactivity

Maintenance of secondary containment as required by TSs

Refueling activities, including fuel handling and fuel receipt inspections

Fatigue management

Tracking of startup prerequisites, walkdown of the drywell (primary containment) to

verify that debris had not been left which could block the emergency core cooling

system suction strainers, and startup and ascension to full power operation

Identification and resolution of problems related to refueling outage activities

Foreign Object Search and Retrieval (FOSAR) for missing baffle bolts and locking

tabs

During this outage, PSEG replaced 189 degraded baffle bolts in the Unit 1 reactor vessel

baffle assembly. This emergent project resulted in the extension of the outage schedule

from 36 days to 106 days.

b. Findings

No findings were identified.

1R22 Surveillance Testing (71111.22 - 5 samples)

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of

selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR,

and PSEG procedure requirements. The inspectors verified that test acceptance criteria

were clear, tests demonstrated operational readiness and were consistent with design

documentation, test instrumentation had current calibrations and the range and accuracy

for the application, tests were performed as written, and applicable test prerequisites

were satisfied. Upon test completion, the inspectors considered whether the test results

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supported that equipment was capable of performing the required safety functions. The

inspectors reviewed the following surveillance tests:

Unit 1, Manual SI on April 17

Unit 1, 11CA360, control air header supply check valve, as-found local leak rate test

(LLRT) on April 22

Unit 2, 21 RHR In-service Testing on April 1

Unit 2, 22SW223, SW outlet valve to 22 CFCU, stroke time in the required evaluation

range on May 3

Unit 2, Reactor coolant system (RCS) elevated leakrate on May 17

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation (71114.06 - 1 sample)

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine PSEG emergency drill on June 16 to

identify any weaknesses and deficiencies in the classification, notification, and protective

action recommendation development activities. The inspectors observed emergency

response operations in the simulator, technical support center, and emergency

operations facility to determine whether the event classification, notifications, and

protective action recommendations were performed in accordance with procedures. The

inspectors also attended the drill critique to compare inspector observations with those

identified by PSEG staff in order to evaluate PSEGs critique and to verify whether the

PSEG staff was properly identifying weaknesses and entering them into the CAP.

b. Findings

No findings were identified.

2. RADIATION SAFETY

Cornerstones: Occupational and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01 - 6 samples)

a. Inspection Scope

The inspectors reviewed PSEGs performance in assessing and controlling radiological

hazards in the workplace. The inspectors used the requirements contained in 10 CFR

Part 20, TSs, applicable Regulatory Guides (RGs), and the procedures required by TSs

as criteria for determining compliance.

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Inspection Planning

The inspectors reviewed the PIs for the occupational radiation safety cornerstone,

radiation protection (RP) program audits, and reports of operational occurrences in

occupational radiation safety since the last inspection.

Radiological Hazard Assessment (1 sample)

The inspectors conducted independent radiation measurements during walk-downs of

the facility and reviewed the radiological survey program, air sampling and analysis,

continuous air monitor use, recent plant radiation surveys for radiological work activities,

and any changes to plant operations since the last inspection to verify survey adequacy

of any new radiological hazards for onsite workers or members of the public.

Instructions to Workers (1 sample)

The inspectors reviewed high radiation area work permit controls and use; observed

containers of radioactive materials and assessed whether the containers were labeled

and controlled in accordance with requirements.

The inspectors reviewed several occurrences where a workers electronic personal

dosimeter alarmed. The inspectors reviewed PSEGs evaluation of the incidents,

documentation in the CAP, and whether compensatory dose evaluations were

conducted when appropriate. The inspectors verified follow-up investigations of actual

radiological conditions for unexpected radiological hazards were performed.

Contamination and Radioactive Material Control

The inspectors observed the monitoring of potentially contaminated material leaving the

radiological controlled area and inspected the methods and radiation monitoring

instrumentation used for control, survey, and release of that material.

Radiological Hazards Control and Work Coverage (1 sample)

The inspectors evaluated in-plant radiological conditions and performed independent

radiation measurements during facility walk-downs and observation of radiological work

activities. The inspectors assessed whether posted surveys; radiation work permits

(RWPs); worker radiological briefings and RP job coverage; the use of continuous air

monitoring, air sampling, and engineering controls; and dosimetry monitoring were

consistent with the present conditions. The inspectors examined the control of highly

activated or contaminated materials stored within the SF pools and the posting and

physical controls for selected high radiation areas (HRAs), locked high radiation areas

(LHRAs) and very high radiation areas (VHRAs) to verify conformance with the

occupational PI.

Risk-Significant High Radiation Area and Very High Radiation Area Controls (1 sample)

The inspectors reviewed the procedures and controls for HRAs, VHRAs, and radiological

transient areas in the plant.

24

Radiation Worker Performance and Radiation Protection Technician Proficiency

(1 sample)

The inspectors evaluated radiation worker performance with respect to RP work

requirements. The inspectors evaluated RP technicians in performance of radiation

surveys and in providing radiological job coverage.

Problem Identification and Resolution (1 sample)

The inspectors evaluated whether problems associated with radiation monitoring and

exposure control (including operating experience) were identified at an appropriate

threshold and properly addressed in the CAP.

b. Findings

No findings were identified.

2RS2 Occupational As Low As is Reasonable Achievable Planning and Controls

(71124.02 - 3 samples)

a. Inspection Scope

The inspectors assessed PSEGs performance with respect to maintaining occupational

individual and collective radiation exposures as low as is reasonably achievable

(ALARA). The inspectors used the requirements contained in 10 CFR Part 20,

applicable RGs, TSs, and procedures required by TSs as criteria for determining

compliance.

Inspection Planning

The inspectors conducted a review of Salem Station collective dose history and trends;

ongoing and planned radiological work activities; previous post-outage ALARA reviews;

radiological source term history and trends; and ALARA dose estimating and tracking

procedures.

Radiological Work Planning

The inspectors selected the following radiological work activities based on exposure

significance for review:

RWP 13, Control Rod Drive Activities

RWP 14 , Pressurizer Activities

RWP 17, Primary SG Work

For each of these activities, the inspectors reviewed: ALARA work activity evaluations;

exposure estimates; and exposure reduction requirements.

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Verification of Dose Estimates and Exposure Tracking Systems

The inspectors reviewed the current annual collective dose estimate; basis methodology;

and measures to track, trend, and reduce occupational doses for ongoing work activities.

The inspectors evaluated the adjustment of exposure estimates or re-planning of work.

Source Term Reduction and Control (1 sample)

The inspectors reviewed the current plant radiological source term and historical trend,

plans for plant source term reduction, and contingency plans for changes in the source

term as the result of changes in plant fuel performance or changes in plant primary

chemistry.

The inspectors observed radiological work activities and evaluated the use of shielding

and other engineering work controls based on the radiological controls and ALARA plans

for those activities.

Radiation Worker Performance (1 sample)

The inspectors observed radiation worker and RP technician performance during

radiological work to evaluate worker ALARA performance according to specified work

controls and procedures. Workers were interviewed to assess their knowledge and

awareness of planned and/or implemented radiological and ALARA work controls.

Problem Identification and Resolution (1 sample)

The inspectors evaluated whether problems associated with ALARA planning and

controls were identified at an appropriate threshold and properly addressed in the CAP.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation (71124.03 - 3 samples)

a. Inspection Scope

The inspectors reviewed the control of in-plant airborne radioactivity and the use of

respiratory protection devices in these areas. The inspectors used the requirements in

10 CFR Part 20, RG 8.15, RG 8.25, NUREG/CR-0041, TS, and procedures required by

TS as criteria for determining compliance.

Inspection Planning

The inspectors reviewed the UFSAR to identify ventilation and radiation monitoring

systems associated with airborne radioactivity controls and respiratory protection

equipment staged for emergency use. The inspectors also reviewed respiratory

protection program procedures and current PIs for unintended internal exposure

incidents.

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Engineering Controls (1 sample)

The inspectors reviewed operability and use of both permanent and temporary

ventilation systems, and the adequacy of airborne radioactivity radiation monitoring in

the plant based on location, sensitivity, and alarm set-points.

Use of Respiratory Protection Devices (1 sample)

The inspectors reviewed the adequacy of PSEGs use of respiratory protection devices

in the plant to include applicable ALARA evaluations, respiratory protection device

certification, respiratory equipment storage, air quality testing records, and individual

qualification records.

Problem Identification and Resolution (1 sample)

The inspectors evaluated whether problems associated with the control and mitigation of

in-plant airborne radioactivity were identified at an appropriate threshold and addressed

by PSEGs CAP.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment (71124.04 - 2 samples)

a. Inspection Scope

The inspectors reviewed the monitoring, assessment, and reporting of occupational

dose. The inspectors used the requirements in 10 CFR Part 20, RGs, TSs, and

procedures required by TSs as criteria for determining compliance.

Inspection Planning

The inspectors reviewed: RP program audits; National Voluntary Laboratory

Accreditation Program (NVLAP) dosimetry testing reports; and procedures associated

with dosimetry operations.

Source Term Characterization (1 sample)

The inspectors reviewed the plant radiation characterization (including gamma, beta,

alpha, and neutron) being monitored. The inspector verified the use of scaling factors to

account for hard-to-detect radionuclides in internal dose assessments.

External Dosimetry

The inspectors reviewed: dosimetry NVLAP accreditation; onsite storage of dosimeters;

the use of correction factors to align electronic personal dosimeter results with NVLAP

dosimetry results; dosimetry occurrence reports; and CAP documents for adverse trends

related to external dosimetry.

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Internal Dosimetry (1 sample)

The inspectors reviewed: internal dosimetry procedures; whole body counter

measurement sensitivity and use; adequacy of the program for whole body count

monitoring of plant radionuclides or other bioassay technique; adequacy of the program

for dose assessments based on air sample monitoring and the use of respiratory

protection; and internal dose assessments for any actual internal exposure.

Special Dosimetric Situations

The inspectors reviewed external dose monitoring of workers in large dose rate gradient

environments.

Problem Identification and Resolution

The inspectors evaluated whether problems associated with occupational dose

assessment were identified at an appropriate threshold and properly addressed in the

CAP.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation (71124.05 - 1 sample)

a. Inspection Scope

The inspectors reviewed performance in assuring the accuracy and operability of

radiation monitoring instruments used to protect occupational workers during plant

operations and from postulated accidents. The inspectors used the requirements in

10 CFR Part 20; RGs; applicable industry standards; and procedures required by TSs as

criteria for determining compliance.

Inspection Planning

The inspectors reviewed: Salem Station UFSAR; RP audits; records of in-service survey

instrumentation; and procedures for instrument source checks and calibrations.

Walkdowns and Observations

The inspectors checked the calibration and source check status of various portable

radiation survey instruments and contamination detection monitors for personnel and

equipment.

Calibration and Testing Program

The inspectors reviewed the calibration standards used for portable instrument

calibrations and response checks to verify that instruments were calibrated by a facility

that used National Institute of Science and Technology traceable sources.

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Problem Identification and Resolution (1 sample)

The inspectors verified that problems associated with radiation monitoring

instrumentation (including failed calibrations) were identified at an appropriate threshold

and properly addressed in the CAP.

b. Findings

No findings were identified.

Cornerstone: Public Radiation Safety (PS)

2RS7 Radiological Environmental Monitoring Program (71124.07 - 2 samples)

a. Inspection Scope

The inspectors reviewed the Radiological Environmental Monitoring Program (REMP) to

validate the effectiveness of the radioactive gaseous and liquid effluent release program

and implementation of the Groundwater Protection Initiative (GPI). The inspectors used

the requirements in 10 CFR Part 20; 40 CFR Part 190; 10 CFR Part 50, Appendix I; TSs;

Offsite Dose Calculation Manual (ODCM); Nuclear Energy Institute 07-07; and

procedures required by TSs as criteria for determining compliance.

Inspection Planning

The inspectors reviewed: Salem and Hope Creek Stations 2015 annual radiological

environmental and effluent monitoring reports; REMP program audits; ODCM changes;

land use census; UFSAR; and inter-laboratory comparison program results.

Site Inspection (1 sample)

The inspectors walked down various passive dosimeter and air and water sampling

locations and reviewed associated calibration and maintenance records. The inspectors

observed the sampling of various environmental media as specified in the ODCM and

reviewed any anomalous environmental sampling events including assessment of any

positive radioactivity results. The inspectors reviewed any changes to the ODCM. The

inspectors verified the operability and calibration of the meteorological tower instruments

and meteorological data readouts. The inspectors reviewed environmental sample

laboratory analysis results, laboratory instrument measurement detection sensitivities,

laboratory quality control program audit results, and the inter- and intra-laboratory

comparison program results. The inspectors reviewed the groundwater monitoring

program as it applies to selected potential leaking structures, systems, or components;

and 10 CFR 50.75(g) records of leaks, spills, and remediation since the previous

inspection.

Groundwater Protection Initiative Implementation

The inspectors reviewed: groundwater monitoring results; changes to the Groundwater

Protection Initiative (GPI) program since the last inspection; anomalous results or

missed groundwater samples; leakage or spill events including entries made into the

decommissioning files (10 CFR 50.75 (g)); evaluations of surface water discharges; and

29

PSEGs evaluation of any positive groundwater sample results including appropriate

stakeholder notifications and effluent reporting requirements.

Identification and Resolution of Problems (1 sample)

The inspectors evaluated whether problems associated with the REMP were identified at

an appropriate threshold and properly addressed in PSEGs CAP.

b. Findings

No findings were identified.

4. OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with

Complications (6 samples)

a. Inspection Scope

The inspectors reviewed PSEG submittals for the following Initiating Events Cornerstone

PIs for the period of July 1, 2015 through June 30, 2016.

Unit 1 & 2 Unplanned Scrams

Unit 1 & 2 Unplanned Power Changes

Unit 1 & 2 Unplanned Scrams with Complications

To determine the accuracy of the PI data reported during those periods, inspectors used

definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors

reviewed PSEG operator narrative logs, maintenance planning schedules, condition

reports, event reports, and NRC integrated IRs to validate the accuracy of the

submittals.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution (71152 - 4 samples)

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the

inspectors routinely reviewed issues during baseline inspection activities and plant

status reviews to verify PSEG entered issues into their CAP at an appropriate threshold,

gave adequate attention to timely corrective actions, and identified and addressed

adverse trends. In order to assist with the identification of repetitive equipment failures

and specific human performance issues for follow-up, the inspectors performed a daily

30

screening of items entered into their CAP and periodically attended condition report

screening meetings. The inspectors also confirmed, on a sampling basis, that, as

applicable, for identified defects and non-conformances, PSEG performed an evaluation

in accordance with 10 CFR Part 21.

b. Findings

No findings were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a semi-annual review of site issues to identify trends that

might indicate the existence of more significant safety concerns. As part of this review,

the inspectors included repetitive or closely-related issues documented by PSEG in the

CAP and repetitive or closely-related issues that may have been documented by PSEG

outside of the CAP, such as trend reports, PIs, major equipment problem lists, system

health reports, MR assessments, and maintenance or CAP backlogs. The inspectors

also reviewed PSEG CAP database for the first and second quarters of 2016 to assess

notifications written in various subject areas (equipment problems, human performance

issues, etc.), as well as individual issues identified during the inspectors daily condition

report review (Section 4OA2.1). The inspectors reviewed the PSEG CAP trending data,

conducted under LS-AA-125, to verify that PSEG personnel were appropriately

evaluating and trending adverse conditions in accordance with applicable procedures.

a. Findings and Observations

No findings were identified.

Equipment Reliability (Steady)

The inspectors documented an adverse trend in either equipment reliability or unplanned

entries into TS shutdown limiting conditions for operation (LCO) in each of the previous

four semi-annual trend review periods (IRs 05000272; 311/2014003, 2014005, 2015002

and 2015004). In February 2016, in response to PSEGs unplanned LCO performance

goal not being met, PSEG performed Common Cause Evaluation (CCE) 70184208,

Unplanned Shutdown LCO Goal Not Met. The CCE was completed in April of 2016, with

the following results:

A trend of data over an 18-month period from August 2014 through January 2016

identified 68 unplanned shutdown LCOs, which far exceeded the station goal of

no more than 8 in a 12-month rolling average. PSEGs CCE concluded:

1) 15 LCO entries were attributed to faulty parts; 2) 10 entries were attributed to

equipment not being repaired in a timely manner; and 3) more follow up

evaluations were warranted:

o Work Group Evaluation (WGE) 70185245, Follow up Evaluation from

Unplanned shutdown LCOs, was performed to further evaluate the

10 entries attributed to equipment not being repaired in a timely manner.

PSEG attributed the cause to ineffective development and

31

implementation of equipment reliability strategies to ensure reliability until

long-term elimination or mitigating actions were in place. Actions were

assigned to develop bridging strategies for Plant Health Committee items

and rollout to Station Oversight Committee (SOC) and Management

Review Committee (MRC) an expectation that if an unplanned LCO

occurs, a causal evaluation should be performed.

The inspectors noted some improvement in the area of unplanned entries into TS LCOs

in recent months; specifically, 44 unplanned shutdown LCOs occurred from June 2015

to April 2016, but only seven occurred in the last 3 months of this 10 month period. The

inspectors determined that the adverse trend of equipment failures did not constitute a

performance deficiency, because the trend, by itself, did not constitute a violation of any

NRC requirement. The inspectors inspected individual equipment failures as ROP

baseline inspection samples documented in other sections of this report.

Main Control Room Deficiencies (Steady with recent improvement)

The inspectors noted an adverse trend in main control room deficiencies, as evident by a

Red station performance metric dating back to mid-2015, when the station metric was

redefined to align with the current industry metric. Specifically, in June of 2016, Unit 1

had 69 and Unit 2 had 45, versus a red performance metric threshold of 16 or more.

However, the inspectors noted recent improvements in this area. Specifically, Unit 1

reduced the backlog from 99 in January 2016 to 69 in June, and Unit 2 reduced the

backlog from 73 before the fall 2015 refueling outage to 45 in June 2016.

Untimely Reportability Determinations (Steady)

In Section 4OA2.2 of IR 2015-004, the inspectors identified that past operability

determinations were untimely in supporting conclusions of LER reportability in 60 days,

and listed multiple examples. In response to a LER 05000311/2016-001-000 being

submitted well beyond 60 days from the occurrence of the event (see Sections 4OA2.3

and 4OA7 of this report), PSEG performed a review under apparent cause evaluation

(ACE) 70183590, to determine the extent of condition relative to missed or late reports

under 10 CFR 50.72 and 50.73. PSEG concluded the following: 1) The execution of

CAP does not support timely completion of evaluation products to support 60-day LER

submittals; 2) SOC and MRC have a low threshold for requesting reportability reviews;

and 3) Salem has a high number of supplemental LERs relative to the industry (four in

2015 versus an industry average of less than one), indicating that CAP does not support

timely cause evaluation completion, which require LERs to be supplemented. The

inspectors noted that PSEGs conclusion 3 above is consistent with a previously

identified trend by the inspectors documented in Section 4OA2.2 of IR 2015002, which

listed a steady increase in CAP evaluation products and subsequent trend of CAP

products falling behind station timeliness goals. As a result of the ACE listed above,

PSEG issued a temporary standing order to develop interim guidance until process

improvements and controls were institutionalized for reportability, assigned corrective

actions to develop procedure improvements and controls for accompanying reportability

reviews, and to develop the appropriate change management plan for process changes

to perform reportability reviews. The inspectors did not identify any actual violations of

10 CFR 50.72 or 50.73 during the performance of this inspection. The timeliness of

reportability determinations remains a minor adverse trend.

32

Status Control and Human Performance Events (Improving)

The inspectors previously documented an adverse trend in status control in Section

4OA2.5 of IR 2014005. In December of 2015, Nuclear Oversight identified an adverse

trend in status control. In February of 2016, PSEG completed a CCE in response to the

adverse trend in plant status control. Additionally, status control was a focus area for the

station in 2016. Since that time, the inspectors noted considerable improvement in the

area of status control. Specifically, as of June 1, 2016, the station achieved 181 status

control event free days. However, in recent months, the inspectors noted several human

performance events that were not classified as status control events, though they reflect

many of the same behavioral breakdowns in standards and fundamentals. Examples

include:

April 17: 1B EDG invalid actuation: During the performance of solid state

protection system testing in Mode 6 (refueling), the 1B EDG unexpectedly started

while an operator in the field was attempting to replace a light bulb on the test

box. PSEG performed an investigation and determined that the most likely

cause was due to the operators finger bumping the block switch during the bulb

replacement, which was enough pressure to allow the test block signal to be

momentarily interrupted. PSEG reported this event as a telephone notification

under 10 CFR 50.73(a)(1) and (a)(2)(iv)(A) on June 15.

April 25: #1 Emergency Compressed Air Compressor trip during leak test -

PSEG performed Quick Human Performance Investigation (QHPI) 70186240 and

determined the operator in the control room did not understand the report from

the equipment operator in the field, and determined that three-way

communication was not used when it should have been.

April 19: 22B circulator bypass valve operated in the wrong direction - PSEG

performed QHPI 71085972 and determined that an equipment operator did not

fully open the 22B circulator outlet valve prior to attempting remote closure of the

22B circulator bypass, which resulted in the bypass valve failing to stroke closed.

March 27: Station Blackout (SBO) air compressor tripped - the equipment

operator did not follow procedure while testing the SBO air compressor, resulting

in a trip of the compressor (20723821).

The inspectors determined that none of the issues above were of more than minor

significance, because none of them resulted in a significant plant transient or loss of a

mitigating system. The inspectors determined that although the trend in events

classified as status control had improved, the behaviors that contributed to them were

still present.

.3 Annual Sample: Unit 2 Auxiliary Feedwater Loop Response Time Exceeded Technical

Specifications

a. Inspection Scope

The inspectors performed an in-depth review of PSEGs identification, evaluation, and

resolution following the discovery that a channel of the 21 AFW pump engineered

safety feature actuation system (ESFAS) automatic actuation logic was inoperable.

33

On November 18, 2015, maintenance personnel compiling test data, collected on

October 18, 2015, during the Unit 2 plant shutdown for the fall 2015 refueling outage,

determined that the pump instrumentation loop time response exceeded test acceptance

criteria. At the time, Unit 2 was shut down in a refueling outage and AFW was not

required. The cause of the slow loop response was due to the isolation valve to the

21 AFW pump discharge pressure transmitter (2PA3450) being closed. The pressure

transmitter provided input into the pump run-out protection and flow control circuit.

The closed isolation valve caused the pressure transmitter to take longer to sense pump

discharge pressure, which resulted in the slow opening of the pump SG flow control

valves (valves 23AF21 and 24AF21). PSEGs investigation determined that the

condition likely existed since April 20, 2015, following the completion of maintenance on

the pressure transmitter. On January 19, 2016, PSEG determined that the condition

was reportable to the NRC. PSEG initiated an ACE to determine the cause of the

untimely review and evaluation of the surveillance data collected on October 18, 2015,

and a WGE to determine the cause of the improperly positioned isolation valve to

pressure transmitter 2PA3450. The inspectors performed an in-depth review of the ACE

and WGE and corrective actions associated with the issues documented in Orders

70183590 and 70182519. PSEG submitted Licensee Event Report (LER)

05000311/2016-001-000, AFW Loop Response Time Exceeded TSs, on March 21,

2016, as an operation or condition which was prohibited by the plants TS. The

inspectors review of the LER is documented in Section 4OA3.1 of this report. Section

4OA7 documents the enforcement aspects related to the LER.

The inspectors assessed PSEGs problem identification threshold, causal analysis,

extent of condition reviews, compensatory actions, and the prioritization and timeliness

of corrective actions to determine whether PSEG was appropriately identifying,

characterizing, and correcting problems associated with these issues and whether the

planned or completed corrective actions were appropriate. The inspectors compared

the actions taken to the requirements of PSEGs CAP and 10 CFR Part 50, Appendix B.

In addition, the inspectors reviewed documentation associated with this issue, and

interviewed engineering and maintenance personnel to assess the effectiveness of

the implemented and planned corrective actions.

b. Findings and Observations

No findings were identified.

Maintenance personnel compiling 21 AFW pump loop time response test data identified

the slow response times for valves 23AF21 and 24AF21, and entered this issue into the

CAP as NOTF 20710947. During their review, PSEG identified that the instrument

isolation valve for the 21 AFW pump discharge pressure transmitter (2PA3450) was

closed versus the required position of open. The improperly positioned valve was

promptly placed into the required open position. PSEG entered the improperly

positioned valve into the CAP as NOTF 20709417, and performed a prompt investigation

and a WGE. The inspectors determined that action taken by PSEG upon discovery of

the slow response times for valves 23AF21 and 24AF21 were prompt and appropriate.

The inspectors reviewed Order 70182519, which documented the WGE for instrument

isolation valve for 2PA3450 being found in the incorrect position. Although the actual

cause of the improperly positioned isolation valve was indeterminate, PSEG concluded

that the condition most likely existed since April 20, 2015, when maintenance was last

34

performed on 2PA3450. Corrective actions included plans to install human factors tools

(i.e., additional measure devices) on all transmitter isolation valves located in both the

Unit 1 and 2 AFW instrumentation panels. The inspectors concluded that PSEGs

planned corrective action was appropriate.

The inspectors reviewed the timeline of events from the collection of test data on

October 18, 2015, until the submittal of the LER for the condition prohibited by TS

related to the slow instrument loop response time for the 21 AFW pump. The inspectors

concluded that information was available to PSEG personnel on November 20, 2015,

that the condition was potentially reportable when the cause was determined to be due

to the incorrectly positioned instrument isolation valve to 2PA3450. However, the

required LER was not submitted until March 21, 2016.

The inspectors reviewed PSEGs investigation into the reportability timeliness issue, as

documented in Order 70183590. PSEG determined that the cause was due to work

tracking assignments not being made to facilitate identification and completion of the

required past operability review in accordance with Engineering standard practice. The

normal practice to evaluate issues for potential past operability/reportability is for the

SOC to assign a technical evaluation to Engineering to review. In this case an action

item was assigned to Engineering versus a technical evaluation. The due dates for

action items are allowed to be extended by the assignee whereas, the process of

extending technical evaluations has more stringent controls. Therefore, the priority of

the action item was not established at the correct threshold by the assigned

engineering supervisor. This resulted in extensions of the due date for the past

operability/reportability review. PSEGs corrective actions taken or planned included

issuance of an Operations standing order, which provided additional interim guidance for

performing past operability and reportability reviews, and to develop process

improvements and controls for accomplishing past operability and reportability reviews.

The inspectors concluded that the actions taken or planned appeared to appropriately

address the reportability timeliness issue. In accordance with IMC 0612, "Power

Reactor Inspection Reports," the above timeliness of reportability issue constituted a

violation of minor significance that is not subject to enforcement action in accordance

with the Enforcement Policy.

As discussed in Order 70183590, PSEG recognized that the SOC inappropriately

assigned an action item versus the more appropriate technical evaluation to

Engineering for the past operability/reportability review. The inspectors observed that

actions taken by PSEG did not directly address the shortfall of the SOC in this case.

The inspectors noted that there was a low level assignment for the SOC to evaluate for a

human performance crew clock reset; however, the clock reset was determined to not be

necessary. The inspectors noted that the other actions taken or planned discussed

above appeared to be adequate to address the inappropriate extensions of past

operability and reportability reviews.

In NRC Inspection Report 05000272, 05000311/2015004, dated February 10, 2016, a

problem identification and resolution adverse trend was documented related to past

operability determinations being untimely in supporting conclusions of LER reportability

within sixty days. The inspectors concluded that the untimely past operability and

reportability review of the failed 21 AFW pump instrument loop time response test as an

additional example of the adverse trend identified in NRC IR 05000272,

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05000311/2015004 and updated in Section 4OA2.2 of this report. At the end of this

inspection period, PSEG had not entered this adverse trend into their CAP.

.4 Annual Sample: Struthers-Dunn Relay Failures in Safety-Related Applications

a. Inspection Scope

The inspectors performed an in-depth review of PSEGs ACE and corrective actions

associated with NOTF 20681569 related to a 21 containment spray (CS) pump failure to

start. The 21 CS pump failed to start on October 2, 2015, during post-maintenance

testing following scheduled maintenance. The 21 CS pump failure to start was

investigated by PSEG during subsequent troubleshooting. Additionally, a failure modes

and causal table determined the most likely cause for the failure to start was from a

starting relay high contact resistance. PSEG postulated that contact contamination

created a high resistance condition that was subsequently cleared due to the wiping

action of the relay contact. The starting relay was a Struthers-Dunn Model 219BBX-240

and was replaced. The failed relay was sent for failure analysis to an offsite laboratory.

The lab was unable to repeat the high resistance contact operation that was observed at

Salem. The lab functional testing did not yield any deficiencies or failure mechanisms.

The inspectors assessed PSEGs problem identification threshold, causal analyses,

technical analyses, extent of condition reviews, and the prioritization and timeliness of

corrective actions to determine whether PSEG was appropriately identifying,

characterizing, and correcting problems associated with this issue. The inspectors

reviewed the circumstances of this relay failure issue to ascertain the appropriateness of

corrective actions. The inspectors also assessed PSEGs corrective actions to prevent

recurrence. The inspectors compared the actions taken to the requirements of PSEGs

CAP and 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action. In addition, the

inspectors reviewed documentation associated with this issue, including condition

reports, and interviewed engineering personnel to assess the effectiveness of the

planned and implemented corrective actions.

b. Findings and Observations

No findings were identified.

The Struthers-Dunn relays in critical applications were all replaced in 1996 and 1997

during extended unit shutdowns. From about 2000 to 2015, Salem experienced

Struthers-Dunn relay failures in critical applications at about one MR functional failure

per year. In May 2013, after a Struthers-Dunn relay failure associated with the

15 containment fan cooling unit (CFCU), PSEG developed extensive corrective actions

to revise preventive maintenance (PM) templates and determine an appropriate

replacement periodicity. An accelerated testing program was a corrective action and

completed in March 2014 to determine the number of relay operations when the contacts

gold flashing began to wear away exposing the silver base. Exposing the silver contact

base leads to a corrosion condition called sulfidation creating a high resistance between

relay contacts. Offsite laboratory analysis of previous Struthers-Dunn relays had

identified worn gold flashing and sulfidation.

PSEG determined from the accelerated relay testing program that Struthers-Dunn relays

in CFCU applications should be replaced every 10 years. The CFCUs have more

36

frequent equipment on/off cycles compared to other critical Struthers-Dunn applications.

PSEG determined all other Struthers-Dunn relay replacements should be replaced at

20 years. PSEG established the 20 year replacement interval based on 400 relay

operations for the equipment considered. However, the inspectors noted that for some

relay applications, major gold flashing wear or wiping resulting in areas of exposed silver

was observed from the accelerated failure testing results at just 350 relay operations.

PSEG generated notification 20734284 in response to the inspectors observation for

resolution and to reevaluate the intended 20 year replacement periodicity.

The corrective action due dates for the final PM templates are due in August 2016.

PSEG accelerated and completed the Struthers-Dunn relay replacements in all CFCU

applications. The inspectors noted that if PSEG finalizes a 20 year replacement for

non-CFCU applications, considering that all Struthers-Dunn relays were replaced in

1996 to 1997, then all Struthers-Dunn relays would now or in the near term require

replacement. PSEG initiated notification 20734280 in response to the inspectors

observation for resolution.

.5 Annual Sample: Unexpected Number of Degraded Baffle-Former Bolts Discovered in

the Unit 1 Reactor Pressure Vessel

a. Inspection Scope

The inspectors performed an in-depth review of PSEGs technical evaluation and

corrective actions associated with NOTF 20726264 for baffle-former (baffle) bolts found

with indications of degradation during the spring 2016 Salem Unit 1 24th refueling outage

(1R24). PSEG performed ultrasonic examinations of the baffle bolts in accordance with

their procedures in response to recent industry operating experience and 1R24 visual

examination results indicating 18 visually damaged baffle bolts. After an unexpected

number of degraded baffle bolts were discovered, PSEG staff entered the issue into their

corrective action program as NOTF 20727538 and reported the issue to the NRC as

Event Notification No. 51902 on May 3, 2016, because the as-found number and

location of degraded bolts, which were mainly concentrated in three of the eight baffle

assemblies, represented an unanalyzed condition. PSEG staff completed corrective

actions to replace 189 of 192 potentially degraded baffle bolts on Unit 1. As

documented in Section 1R18, PSEG did not remove and replace three bolts that were

potentially degraded due to difficulties encountered during the removal/replacement

process.

The baffle bolts help secure vertical plates (also referred to as baffle plates) inside the

reactor vessel, which then forms a structure surrounding the reactor fuel assemblies to

orient the fuel and to direct coolant flow through the core. A sufficient number of baffle

bolts are required to remain intact to secure the baffle plates in place so as to not affect

control rod insertion or impede emergency core cooling flow during postulated accident

conditions. Bolt heads that separate and are no longer held in place by bolt lock-tabs

can also become a loose parts concern.

The inspectors assessed whether PSEG acceptable baffle bolt pattern analysis for

Unit 1 was completed in accordance with the NRC-approved methodology and provided

appropriate structural margin for the next cycle of operation to ensure the Unit 1 baffle

plates will remain in place during both normal operation and limiting postulated accident

conditions. The inspectors also assessed whether PSEGs evaluations of the baffle

37

bolts installed in Salem Unit 2 were technically sufficient to conclude the Unit 2 baffle

assembly will perform as intended until the next planned refueling outage, at which time

PSEG plans to examine the bolts. The inspectors reviewed PSEGs procedures for

determining the functionality and operability of degraded systems, components and

structures as they relate to Unit 2. Additionally, the inspectors interviewed PSEG

engineering personnel and contractor staff to discuss the results of PSEGs technical

evaluations and to assess the effectiveness of the implemented and planned corrective

actions.

The inspectors assessed PSEGs problem identification threshold, cause analyses,

extent of condition, compensatory actions, and the prioritization and timeliness of

PSEGs corrective actions to determine whether PSEG staff were properly identifying,

characterizing, and correcting problems associated with this issue and whether the

planned or completed corrective actions were appropriate. The inspectors compared the

actions taken to PSEGs corrective action program, operability determination process,

and the requirements of 10 CFR Part 50, Appendix B. The inspectors observed portions

of baffle bolt replacement activities at Unit 1 and reviewed the final visual examination of

the baffle bolts and plates once the work was completed.

b. Observations

The NRC responded to the initial discovery of an unexpected number of baffle bolts

found degraded at Salem Unit 1 by implementing a comprehensive inspection plan

consisting of various baseline inspection samples to assess the extent of the issue and

to determine the necessary NRC actions. A previously planned ISI sample (Refer to

Section 1R08) was expanded to include a review of the capability of the NDE techniques

for ultrasonically testing (UT) the baffle bolts, to evaluate the UT results, and to observe

a portion of bolt replacement activities on-site. Two permanent modification samples

(Refer to Section 1R18) were conducted to review the design change package and

evaluations associated with the new, replacement baffle bolts, and to review the PSEG

design change package documenting the as-left baffle bolting pattern in Unit 1. NRC

resident inspectors reviewed PSEGs foreign material controls and loose parts analysis

(Refer to Section 1R20) to address the potential for missing bolt heads and concluded it

would not impact safe operation of the plant.

NRC Region I based inspectors, accompanied by an expert from the NRC Office of

Nuclear Reactor Regulation, completed this annual problem identification and resolution

inspection sample, to verify that PSEGs evaluations and corrective action to replace

Unit 1 baffle bolts were completed in accordance with NRC approved methodology to

support a conclusion that the Unit 1 baffle assembly meets the plant design basis. The

inspectors also reviewed the adequacy of PSEGs technical evaluations completed to

determine whether there is a reasonable expectation the Unit 2 baffle assembly will

perform as intended during the current operating cycle. The results of this review are

discussed herein and in Section 1R15 of this report.

At the completion of this inspection, PSEGs conduct of a RCE to determine the causes

of the failure of the baffle bolts in Unit 1 was ongoing. The inspectors determined

PSEGs RCE will not be completed until after laboratory tests and analyses, planned for

fall 2016, are performed on a sample of the bolts removed from Unit 1. PSEGs

technical evaluation discussed the cause of the degraded baffle bolts as primarily due to

IASCC. This determination was based on industry operating experience related to baffle

38

bolt failure in both foreign and domestic plants, is a known degradation mechanism and

the operational and physical characteristics of both Salem plants indicate that they are

susceptible to this mechanism. The inspectors reviewed PSEGs technical evaluation

and the supporting operating experience related to baffle bolt failures at other plants.

IASCC is a cracking mechanism that occurs over a long period of time when susceptible

metals are exposed to neutron radiation from the reactor core and stresses as part of

normal design and operation. The inspectors determined PSEG identified the likely

cause of the baffle bolt degradation and their plans to complete a RCE when additional

metallurgical information was available was appropriate.

Following identification of the degraded baffle bolts on Unit 1, PSEGs immediate

corrective action was to analyze the as-found condition and begin replacing bolts that

either had visual indications of bolt failure (protruding bolt head for example), did not

pass UT examination, or were not accessible for UT examination. The as-found number

and pattern of these bolts exceeded the acceptance criteria in the plants analysis that

was prepared in advance of the baffle bolt examinations; therefore, PSEG reported this

discovery to the NRC as an unanalyzed condition in Event Notification 51902 on May 3,

2016. PSEG staff completed corrective actions to replace 189 of 192 potentially

degraded baffle bolts. PSEG did not remove and replace three bolts that were

potentially degraded due to difficulties encountered during the removal/replacement

process. As previously documented in Section 1R18, one bolt had an indication during

ultrasonic testing but was not visibly damaged. The second bolt was inaccessible for

ultrasonic testing, which would have required replacement. The third bolt had

successfully passed an ultrasonic test but had a visual indication on one of the lock bar

welds which may have indicated a crack in the weld.

The inspectors determined that PSEG staff performed an acceptable bolt pattern

analysis that evaluated the replacement bolt pattern for Unit 1. The inspectors found

the results of the analysis accounted for a conservative failure rate of bolts and provided

appropriate margin for one cycle of operation. The inspectors verified that PSEGs

methodology for its acceptable bolt pattern analyses, including its determination of

margin, was consistent with the NRC-approved methodology in topical report

WCAP-15029-NP-A (ML15222A882). The inspectors determined that PSEG staff

tracked corrective actions to re-examine the Unit 1 baffle bolts during the next planned

refueling outage. The inspectors noted the new baffle bolts were made of a material

(316 SS) with improved resistance to IASCC and included an improved design to reduce

the stresses at the head to shank transition, both of which are enhancements compared

to the original bolts.

As part of an extent of condition assessment, PSEG entered NOTF 20727590 in its

corrective action program to evaluate the potential for degraded baffle bolts on Unit 2.

PSEG operators performed an IOD and concluded that the baffle assembly was

operable. PSEG staff performed a subsequent technical evaluation that concluded

Unit 2 would experience less baffle bolt degradation than Unit 1 based on several plant

factors. The inspectors reviewed PSEGs technical evaluations, including the inputs for

the operability determination, and noted that PSEG staff concluded there was not a

degraded condition at Unit 2. In consideration of the guidance in PSEGs operability

procedure and operating experience from Unit 1 and other plants, the NRC issued an

NCV in this report because PSEG did not perform an OPEval for Unit 2 as a follow-up to

the IOD for the potential impact on supported systems controlled by the Technical

Specifications (Refer to Section 1R15).

39

As a corrective action, PSEG staff performed OpEval 2016-015 and demonstrated that

the Unit 2 baffle assembly remained operable. The inspectors concluded that this

supplemental evaluation provided adequate technical justification for the continued

operation of Unit 2 until the next refueling outage in spring 2017, at which time PSEG

plans to examine the baffle bolts. PSEG also implemented compensatory measures to

monitor the reactor coolant system for any signs of fuel leakage, which could be an

indicator of baffle bolt failures and to generate additional contingency actions in

response to indications of increased unidentified leakage or receipt of a metal impact

monitoring system alarm.

The inspectors reviewed Westinghouse Nuclear Safety Advisory Letter NSAL-16-1,

which discussed the results of recent baffle bolt inspections and provided

Westinghouses recommendations on this issue. The letter described the plants as most

susceptible (i.e. Tier 1a) to this degradation as Westinghouse 4-loop reactors limited to

those with a down-flow configuration and using Type 347 stainless steel. A non-

proprietary presentation on the contents of NSAL-16-1 can be found at ML16202A063.

The inspectors noted the recommendation was to complete UT volumetric examination

of the baffle bolts at the next scheduled refueling outage, and that PSEG had already

planned this action for Unit 2. The inspectors determined PSEGs overall response to

the issue was commensurate with the safety significance, was timely, and included

appropriate compensatory actions. The inspectors concluded that the actions completed

and planned were reasonable to address the ongoing aging management of baffle bolts.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153 - 4 samples)

.1 Plant Events (2 samples)

a. Inspection Scope

For the plant events listed below, the inspectors reviewed and/or observed plant

parameters, reviewed personnel performance, and evaluated performance of mitigating

systems. The inspectors communicated the plant events to appropriate regional

personnel, and compared the event details with criteria contained in IMC 0309, Reactive

Inspection Decision Basis for Reactors, for consideration of potential reactive inspection

activities. As applicable, the inspectors verified that PSEG made appropriate emergency

classification assessments and properly reported the event in accordance with 10 CFR

50.72 and 50.73. The inspectors reviewed PSEGs follow-up actions related to the

events to assure that PSEG implemented appropriate corrective actions commensurate

with their safety significance.

Unit 1, Baffle to former bolts found broken or degraded on May 3 (EN 51902)

Unit 2, Reactor trip from main turbine trip on June 28 (EN 52048)

b. Findings

No findings were identified.

40

.2 (Closed) LER 05000311/2016-001-000: Auxiliary Feedwater Loop Response Time

Exceeded Technical Specifications

a. Inspection Scope

While evaluating surveillance instrumentation loop time response test data associated

with the 21 AFW pump that was collected during the Unit 2 plant shutdown for the fall

2015 refueling outage, PSEG determined that a channel of the pumps ESFAS

automatic actuation logic was inoperable. In November 2015, PSEG personnel

identified the slow loop response time during surveillance testing. The cause of the slow

loop response was due to the isolation valve to the 21 AFW pump discharge pressure

transmitter (2PA3450) being closed. The pressure transmitter provided input into the

pump run-out protection and flow control circuit. The closed isolation valve caused the

pressure transmitter to take longer to sense pump discharge pressure which resulted in

slow opening of the pump steam generator flow control valves (valves 23AF21 and

24AF21). PSEGs investigation determined that the condition existed since April 20,

2015, following the completion of maintenance on the pressure transmitter. An

engineering review concluded that, although the AFW loop response time test results did

not satisfy TS requirements, the accident analysis assumptions remained valid and the

condition did not result in an unanalyzed condition. This issue is discussed in more

detail in Section 4OA2.1 of this report. No other issues were identified during the review

of the LER. This LER is closed.

b. Findings

The enforcement aspects of this violation are discussed in Section 4OA7.

.3 (Closed) LER 05000311/2016-002-00: Automatic Reactor Trip Due to Main Turbine Trip

a. Inspection Scope

On February 4, Salem Unit 2 automatically tripped from approximately 74 percent 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 AVR volts/hertz over excitation protection

relay. All emergency core cooling systems and emergency safeguards feature systems

functioned as expected. PSEG submitted this LER in accordance with 10 CFR 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)," specifically automatic actuation of

the Reactor Protection System and the Auxiliary Feedwater System for this event. The

inspectors reviewed the LER, the associated cause evaluation, and interviewed PSEG

staff. This LER is closed.

b. Findings

Introduction. A Green, self-revealing FIN was identified against MA-AA-716-010,

Maintenance Planning Process, Revision 18, when PSEG WOs did not specify the

appropriate procedure to perform satisfactory modification testing of the main generator

AVR protective relay (model STV1). Consequently, the relay actuated below its design

setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main turbine and

reactor.

41

Description. On February 4, 2016, Unit 2 experienced an automatic main turbine and

reactor trip from approximately 74 percent power, initiated by a trip of the main generator

AVR STV 1 relay. The STV1 is designed to protect the main generator, main power

transformers, and auxiliary transformer from over-excitation due to over-voltage

operation, and consists of an adjustable pickup dial setting between 1.8 and

2.5 voltz/hertz (V/Hz), ranging from 108 - 150 V at 60 Hz. PSEG design calculation

ES-7.007, Salem Unit 2 Generator and Transformer Protective Relay Setpoint

Determination, Revision 5, established a design setpoint for the STV1 relay of 138 V at

60 Hz, corresponding to a V/Hz dial setting of 2.3, with an associated time delay of

45 seconds. Just prior to the Unit 2 trip on February 4, the main generator was

operating at approximately 26.1 kV following a manual MVAR adjustment, which

corresponded to 2.175 V/Hz sensed at the STV1. After the Unit 2 trip, PSEG

troubleshooting determined the as-found pick-up value of the STV1 was 2.17 V/Hz. The

post-trip sequence-of-event data showed the STV1 time delay unit picked up 45 seconds

after exceeding 2.17 V/Hz, which tripped the AVR and resulted in a loss of field to the

main generator, thereby causing a turbine trip and coincident reactor trip.

In response to the Unit 2 reactor trip, PSEG performed RCE 70183932, Unit 2

Automatic Reactor Trip on Generator Protection, to determine why the STV1 relay

actuated below the design setpoint. PSEG identified two root causes: 1) setpoint drift

due to a damaged rheostat; and 2) the damaged rheostat was not identified due to an

inadequately planned work order that specified a less than adequate post-modification

test method. PSEG DCP 80109718, Salem Unit 2 AVR Replacement, supplement 10,

documented that a modification test was required for the STV1 relay in accordance

with Relay Department test procedures, which subsequently required the use of an

engineering-approved Relay Test Order (RTO). However, Maintenance Planning

prepared WO 60122561-0014 to perform STV1 modification testing without specifying

the applicable test procedures. MA-AA-716-010, step 4.5.7, states If approved

procedure(s) are available which cover all or part of the work scope, then specify in the

work package to perform work in accordance with the procedure(s). Additionally, step

3.1.1 states, in part, Maintenance Planners are responsible to interface with: System

Engineers for providing supplemental technical direction on a case by case basis as

needed; and Maintenance Shops to obtain information needed to produce an

adequately detailed work package.

Additionally, the RCE determined that WO 60122561-0014 directed the PSEG LTS

department to perform modification testing of the STV1 relay. However, LTS utilized

different testing procedures than the Relay department procedures specified in the DCP.

The LTS modification testing performed on October 5, 2015, did not functionally test the

STV1 relay at its design setpoint of 138 volts at 60 Hz, which corresponded to a dial

setting of 2.3 as discussed above. The RCE determined the manufacturer-specified

acceptance testing required verifying the V/Hz pick-up was within one percent of all V/Hz

adjustable dial settings, whereas the LTS procedure required the V/Hz pickup at a four

percent tolerance on the 2.0 dial setting, or four percent of 120 volts at 60 Hz. The

STV1 relay pickup value from the LTS testing on October 5, 2015, fell outside of the one

percent tolerance specified by the manufacturer, and LTS did not have a technical basis

to support an allowable tolerance of four percent. The RCE determined that returning

the relay to the manufacturer-specified setting of one percent would have required

adjusting the damaged rheostat to a position where the relay would not have functioned,

and therefore would have resulted in a failed acceptance test that would have prevented

42

the relay from being installed in the plant. The inspectors verified that the STV1 RTO

specified a one percent tolerance at the design setpoint of 138 volts at 60 Hz.

Analysis. The inspectors determined that a performance deficiency existed because

PSEG WOs did not specify the appropriate procedure to perform satisfactory

modification testing of the main generator AVR protection relay STV1. This issue was

more than minor since it was associated with the procedure quality attribute of the

Initiating Events cornerstone and adversely impacted its objective to limit the likelihood

of events that upset plant stability (main generator and turbine trip) and challenge critical

safety functions. Specifically, due to a work order that was not planned properly, PSEG

did not test the STV1 relay at the applicable design setpoint and manufacture-specified

tolerance. Consequently, the relay actuated below its design setpoint on February 4,

2016, resulting in an automatic trip of the Unit 2 main turbine and reactor. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this

finding was of very low safety significance, or Green, since mitigating equipment relied

up to transition the plant to stable shutdown remained available.

The finding had a cross-cutting aspect in the area of Human Performance, Work

Management, in that the organization implements a work process that includes the need

for coordination with different groups or job activities. Specifically, the PSEG process for

planning the STV1 relay modification test WO included the need for maintenance

planners to coordinate with engineering to provide design setpoint and tolerance

specifications, as well as electrical maintenance departments to verify appropriate test

procedures were specified in the WO. The inspectors determined that PSEG did not

adequately implement the work process in accordance with MA-AA-716-010. [H.5]

Enforcement. MA-AA-716-010, Maintenance Planning Process, Revision 18, step 4.5.7,

states If approved procedure(s) are available which cover all or part of the work scope,

then specify in the WO to perform work in accordance with the procedure(s). Contrary

to the above, PSEG did not specify in the WO to perform work in accordance with

approved Relay department test procedures, and the associated RTO, for modification

testing of the STV1 relay on October 5, 2015. Specifically, due to a work order that was

not planned properly, PSEG did not test the STV1 relay at the applicable design setpoint

and manufacturer-specified tolerance. Consequently, the relay actuated below its

design setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main

turbine and reactor. PSEG entered the issue in CAP as notification 20717849 and

performed RCE 70183932. Planned corrective actions included replacing the failed

STV1 relay with a properly tested STV1 relay, verifying other STV relays were

appropriately tested as an extent of condition, and revising LTS department relay test

procedures to ensure all applicable acceptance criteria are incorporated. This finding

does not involve enforcement action because no violation of a regulatory requirement

was identified. Because this finding does not involve a violation and is of very low safety

significance, it is identified as a Finding. (FIN 05000311/2016002-03, Inadequate Work

Order Planning Results in Main Generator AVR STV Relay Trip)

43

4OA5 Other Activities

.1 (Closed) URI 05000272; 311/2015008-01: Inadequate Maintenance Rule System

Performance Criteria (PC) Selection

a. Inspection Scope

In IR 05000272; 311/2015-008, inspectors identified a URI associated with inadequate

Maintenance Rule Performance Criteria selection.

During this review the inspectors noted approximately 25 high safety significant systems

(HSS) with reliability PC greater than two maintenance preventable functional failures

(MPFFs). According to ER-AA-310-1003, Attachment 3, flowchart Process for Selecting

Reliability Performance Criteria, HSS SSCs, with reliability PC greater than or equal to

two MPFFs require SSC past performance documentation. When the inspectors

requested that PSEG provide past performance documentation for the HSS SSCs with

reliability PC greater than two MPFFs, PSEG provided documentation of HSS SSC PC

approval from 1997, when the MRule Program was first implemented by PSEG. The

inspectors determined this documentation did not support the assigned PC, because it

did not consider the last 18 years of SSC past performance.

The inspectors also reviewed ER-AA-310-1007, Maintenance Rule - Periodic (a)(3)

Assessment. Step 5.11.1.4 states to determine that the number of MPFFs allowed per

evaluation period is consistent with the assumptions in the probabilistic risk assessment

(PRA). Contrary to ER-AA-310-1007, step 5.11.4, the last two periodic (a)(3)

assessments performed by PSEG: April 1, 2011, through September 9, 2012; and

October 1, 2012 through June 30, 2014; did not verify that the number of MPFFs allowed

per evaluation period were consistent with the assumptions in the PRA. Additionally,

ER-AA-310-1003, step 4.3.2, states, in part, that unless justified and approved by the

Maintenance Rule Expert Panel, the number of MPFFs selected, as a Reliability PC,

may not be higher than the PRA-supplied number of functional failures.

The inspectors determined that the failure to meet ER-AA-310-1007, step 5.11.4, and

ER-AA-310-1003, step 4.3.2, was a performance deficiency. However, at the time of

inspection, as documented in the IR referenced above, the inspectors did not have the

information needed to determine whether the performance deficiency was more than

minor. The inspectors reviewed PSEGs actions in response to the URI, to determine

whether the performance or condition of HSS SSCs was effectively controlled through

the performance of appropriate preventive maintenance under 10 CFR 50.65(a)(2), and

also to determine if those HSS SSCs being monitored under 10 CFR 50.65(a)(1) were

assigned appropriate goals and monitoring when considered against the appropriate

reliability PC threshold.

b. Findings

No findings were identified.

PSEG captured the performance deficiency associated with the URI in the CAP under

notifications 20694641, 20699573, and 20716722. In response, the PSEG Engineer

performed detailed reviews of all the HSS reliability performance criteria against the

basic event failure assumptions in the most recent PRA model. For any systems that

44

were identified to have reliability performance criteria deviations from the PRA basic

event failure data, performance criteria changes were proposed to more closely align

with the PRA. Any proposed changes to system performance criteria were scheduled

for review by the Maintenance Rule Expert Panel, including a review of system

performance during the last 36 months. The inspectors observed a sampling of the

Expert Panel meetings, and reviewed meeting minutes for several others. Upon

completion of the PSEG system reviews and expert panel meetings, a total of 12 HSS

had reliability performance criteria reductions to more closely align with PRA failure data.

Five of the 12 systems were already being monitored under 10 CFR Part 50.65(a)(1)

prior to the reduction in performance criteria. None of the 12 systems were moved to

(a)(1) as a result of the performance criteria reductions. The inspectors sampled the

performance criteria adjustments to determine if HSS classified under (a)(2) were being

appropriately monitored, and to verify that (a)(1) systems had appropriate goals

assigned. No performance deficiencies were identified. The inspectors determined that

PSEGs scope of actions restored compliance with ER-AA-310-1007, step 5.11.4, and

ER-AA-310-1003, step 4.3.2.

This URI is closed.

.2 License Renewal Commitments Inspection - Phase I Observation of License Renewal

Activities (71003 - 1 sample)

a. Inspection Scope

License renewal inspections verify the license conditions added as part of the renewed

operating license, regulatory commitments, and selected aging management programs,

and are implemented in accordance with 10 CFR Part 54, Requirements for the

Renewal of Operating Licenses for Nuclear Power Plants. This inspection was

completed during 1R24 to observe the implementation of select aging management

program activities that are only available for observation during a refueling outage. This

inspection is described as Phase 1 in NRC Inspection Manual Procedure 71003, Post-

Approval Site Inspection for License Renewal and is intended to be completed during the

last refueling outage prior to a nuclear power facility entering the period of extended

operation.

As part of this review the inspectors observed the implementation of aging management

programs and activities described in the license conditions, and regulatory commitments,

as well as any testing or visual inspections of systems, structures, and components

which are only accessible at reduced power levels or during a refueling outage.

The inspectors observed the ultrasonic thickness inspection of 1S-FWR-P-21-L1, which

is a 6-inch diameter elbow in the Feedwater Recirculation system. The component is

part of the No. 12 SG Feed pumps 24-inch discharge header. The inspectors observed

the test grid being applied and the recording of measurements in accordance with test

procedure OU-AA-335-004 under the flow accelerated program guidance

ER-AA-430-1001 as directed by WO 30285966.

The inspectors also observed the preparation for the replacement of a Moisture

Separator Reheat Drain system 4-inch diameter piping section. The line is the drain

from the No. 11 West Moisture Separator Reheat Main Steam Coil going to the No. 11

West Main Steam Coil Drain Tank. This was the planned replacement of 27 feet of

45

piping with corrosion resistant P22/Chrome Moly material. The work was being

performed on the 140 Turbine deck, under WO 60123316.

The inspectors observed the No. 12C Miscellaneous Drains drain manifold replacement

spool piece. This 12-inch diameter manifold receives three drain lines from the No. 15A,

B, & C Bleed Steam lines and is being replaced with corrosion resistant P22 (Chrome

Moly) material. The replacement was in progress and performed under WO 60123347.

After reviewing WO 60120251, the inspectors observed the removal and evaluation of

random samples of inaccessible Salem Unit 1 containment liner covered by insulation.

The inspectors observed the containment interior liner insulation being removed,

unremediated containment liner sections, and containment liner sections that were

cleaned, brushed, and prepared for panel installation. The inspectors reviewed

ultrasonic thickness data to verify whether the program was in conformance with

American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,

Section XI.

b. Findings and Observations

No findings were identified.

4OA6 Meetings, Including Exit

On July 28, 2016, the inspectors presented the inspection results to Mr. Robert DeNight,

Salem Operations Director, and other members of the PSEG staff. On August 11, 2016,

an additional exit meeting was conducted and the inspectors presented inspection

results specific to the baffle bolt issues in this report to Mr. Eric Carr, Acting Station Vice

President. During the August 11, 2016 exit meeting, PSEG management stated they

may contest NCV 05000311/2016002-02 (Section 1R15), in a written response within

30 days of the date of this inspection report, using the process described in the cover

letter. Additionally, the inspectors verified that no proprietary information was retained

by the inspectors or documented in this report.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by PSEG

and is a violation of NRC requirements which meets the criteria of the NRC Enforcement

Policy, for being dispositioned as an NCV.

TS LCO 3.3.2.1 requires the ESFAS instrumentation channels and interlocks shown

in Table 3.3-3 shall be operable. Table 3.3-3, Function 8, requires two channels of

AFW automatic actuation logic to be operable in Modes 1, 2, and 3. With the

number of operable channels one less than the required number of channels, TS

LCO 3.3.2.1 requires the inoperable channel to be restored to operable status within

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or, be in at least Hot Standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in at least Hot

Shutdown within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Contrary to TS LCO 3.3.2.1, one less than

the required number of channels of AFW automatic actuation logic were operable

from April 20, 2015, until Unit 2 entered Mode 4 for a scheduled refueling outage on

October 23, 2015. This was due to the 21 AFW pump loop time response being

greater than the allowed TS value because the isolation valve for the pressure

46

override defeat pressure transmitter was in the closed position. PSEG entered this

issue into the CAP as NOTFs 20709417, 20716352, 20710947, and 20711796.

This performance deficiency was more than minor because it was associated with

the human performance attribute of the Mitigating System cornerstone, and

adversely affected the cornerstone objective of ensuring the reliability and capability

of systems that respond to initiating events to prevent undesirable consequences.

The inspectors evaluated this finding using IMC 0609, Appendix A, The Significance

Determination Process for Findings At-Power, Exhibit 2. The inspectors determined

that the finding was of very low safety significance (Green) because the finding did

not represent an actual loss of function of at least a single train for greater than its

TS allowed outage time.

ATTACHMENT: SUPPLEMENTARY INFORMATION

A-1

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Perry, Site Vice President

E. Carr, Acting Site Vice President

J. Barkhamer, PSEG Engineer

J. Bergeron, Superintendent of Instrumentation and Controls

T. Cachaza, Senior Regulatory Compliance Engineer

R. Cary, Environmental Coordinator

L. Clark, Instrument Supervisor

B. Daly, Nuclear Environmental Affairs, Sustainability

D. Denelsbeck, RP Support Supervisor

B. Down, PSEG Engineer

P. Essner, System Engineer

P. Fabian, Salem Steam Generator Engineer

T. Giles, Salem ASME Section XI Program Owner

F. Grenier, RP Supervisor, Dosimetry

M. Hassler, Salem Radiation Protection Manager

B. Kerkorian, Salem Steam Generator Supervisor

D. Kolasinski, Senior Engineer

A. Kraus, Manager, Nuclear Environmental Affairs

T. MacEwen, Principal Compliance Engineer

J. Mallon, Compliance Director

S. Markos, Manager, Design Engineering

J. Marooney, MPR Engineering Consultant

P. Martitz, Technical Support Superintendent

J. Melchionna, Engineering Services

R. Moore, System Engineering Branch Manager

D. Mora, Salem NDE Program Coordinator

G. Morrison, Mechanical Engineer

T. Mulholland, Shift Operations Manager

A. Ochoa, Senior Compliance Engineer

B. Ohmert, System Engineer

T. Oliveri, Salem Unit 1 and Unit 2, NDE Manager

J. ORourke, Regulatory Affairs

J. Owad, Design Engineering

M. Phillips, Regulatory Assurance

M. Pyle, Chemistry Manager

N. Ruvis, Westinghouse

B. Sebastian, Manager Fire Protection/Industrial Safety

J. Stairs, Manager Plant Engineering

C. Wend, Radiation Protection Manager

D. Yilgic, Lead Engineer Quality Control Chemistry

Attachment

A-2

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Open

05000272/2016002-01 URI Baffle-Former Bolts with Identified

Anomalies (Section 1R08)

Open and Closed

05000311/2016002-02 NCV Failure to Follow Operability

Determination Procedure for Unit 2

Baffle-Former Bolts (Section 1R15)05000311/2016002-03 FIN Inadequate Work Order Planning Results in

Main Generator AVR STV Relay Trip

(Section 4OA3.3)

Closed

05000272:311/2015-008-01 URI Inadequate Maintenance Rule System

Performance Criteria Selection

(Section 4OA5)

05000311/2016-001-00 LER Auxiliary Feedwater Loop Response Time

Exceeded Technical Specifications

(Section 4OA3.1)

05000311/2016-002-00 LER Automatic Reactor Trip Due to Main

Turbine Trip (Section 4OA3.3)

A-3

LIST OF DOCUMENTS REVIEWED

  • Indicates NRC-identified

Section 1R01: Adverse Weather Protection

Procedures

SC.OP-SO.500-0001, Trip-A-Unit Scheme Operation, Revision 10

OP-AA-108-107-1001, Electric System Emergency Operations and Electric Systems Operator

Interface, Revision 4

Notifications

20731655* 20731657* 20731658* 20731659* 20731662 20731729*

20731735*

Section 1R04: Equipment Alignment

Procedures

SC.MD-ST.125-0003, Quarterly Inspection and Preventive Maintenance of Units 1, 2, & 3 125

Volt Station Batteries, Revision 30

S1.OP-ST.CAN-0007, Refueling Operations - Containment Closure, Revision 25

S2.OP-SO.SW-0005, Service Water System Operation, Revision 42

S2.OP-SO.ABV-0001, Auxiliary Building Ventilation System Operation, Revision 25

S2.OP-SO.SJ-00001, Preparation of the Safety Injection System for Operation, Revision 19

OP-SA-102-106, Salem Operations Master List of Timed Actions, Revision 0

OP-AA-108-103, Locked Equipment Program, Revision 4

Notifications

20702800 20707221 20724871 20729878* 20732182 20732551

20732785* 20732994* 20733091

Drawings

205337, Sheet 1, No. 2 Unit Auxiliary Building - Ventilation, Revision 43

205242, Sheet 1, No. 2 Unit Service Water Nuclear Area, Revision 81

205242, Sheet 2, No. 2 Unit Service Water Nuclear Area, Revision 76

Maintenance Orders/Work Orders

50180453 50182431 60125981 60129782

Section 1R05: Fire Protection

Procedures

FP-SA-2542, Pre-Fire Plan Unit 2 Spent Fuel/Component Cooling Heat Exchanger and Pump

Area, Revision 0

FP-SA-2552, Pre-Fire Plan Unit 2 Boric Acid Evaporator Unit & Chemistry Area, Revision 0

FP-SA-2651, Pre-Fire Plan Unit 2 Service Water Intake Structure, Revision 0

FP-SA-2555, Pre-Fire Plan Unit 2 Diesel Generator Area, Revision 0

FP-SA-2556, Pre-Fire Plan Unit 2 Inner Piping Penetration Area & Chiller, Revision 0

A-4

Notifications

20723743 20730150* 20732820* 20732836*

Section 1R07: Heat Sink Performance

Notifications

20726947

20727041

20727041

Maintenance Orders/Work Orders

30255437

Section 1R08: In-service Inspection

NDE Procedures

Liquid Penetrant Examination Procedure, OU-AA-335-002, Revision 3

Nondestructive Examination Procedure, Manual Ultrasonic Examination of Vessel Nozzle Inner

Radius Regions, Procedure Number 54-ISI-132-011, 1/27/2011

Nondestructive Examination Procedure, Ultrasonic Examination of Austenitic Piping Welds,

Procedure Number 54-ISI-836-014, 8/21/2013

Areva NP Inc., Nondestructive Examination Procedure, Multi-Frequency Eddy Current

Examination of Tubing, Procedure Number 54-ISI-400-021, 6/12/2013

Notifications

20682192 20694861 20697140 20697577 20697669 20699820

20699859 20699910 20704139 20707057 20707057 20707125

20712181 20712774 20713572 20713573 20713849 20713849

20714082 20716581 20720745 20722494 20724667 20725857

20726340 20726743

Maintenance Orders/Work Orders

60114705

60123261

60126260

Evaluations

70178672 70178814 70178821 70179375 70183001 70185980

Self Assessments

Check-In Self-Assessment, Salem INPO PWR Materials Review, 7/30/2015

NDE Records

Salem Unit 1, Liquid Penetrant Report No. PT-16-002, 11-RHRHEX Vessel Support, 4/15/16

(Summary No.205170)

Salem Unit 1, Liquid Penetrant Report No. PT-16-001, Pipe Lugs 8-RH-2116-10PL-1 thru 4,

4/15/16 (Summary No. 263631)

Salem Unit 1, Liquid Penetrant Report No. PT-16-004, Pipe to Penetration IA, Component 12

SJ-2152-36PS-4, 4/19/16 (Summary No. 263904)

A-5

Salem Unit 1, Liquid Penetrant Report No. PT-16-003, Inlet Nozzle-to-Pump (11 Charging

Pump), Component 6-CV-2111-14R1, 4/15/16 (Summary No. 220757)

Salem Unit 1, Liquid Penetrant Report No. PT-16-005, PIPE TO VALVE (11CS48)

component ID: 8-CS-2114-60, 4/15/16 (Summary No. 356640)

Design Change Package

80092579, Salem Unit 1 - Steam Generator Bowl Drain Repair, SG 11, 12, 13, and 14 (removal

of Alloy 600 and associated 82/182 weld material from each SG Channel Head (SGCH)

bowl drain plugs

PSEG NUCLEAR VTD NUMBER: 900013(019), Title Stress Analysis of Tube-Tubesheet Weld

AREVA RSG, 11/23/15; Calculation Summary Sheet, 7/25/2015.

PSEG Nuclear Work Order 70172201; Areva Reanalysis of Salem Steam Generator tube-to-

tubesheet joint as a friction joint and to provide a revised SG stress analysis to PSEG for

record purposes

WO #60123261, including weld history sheet; Replace SISJ - !SJ248 & 2SJ249

PSEG NUCLEAR LLC VTD NUMBER: AREVA 902739 (001); Salem Unit 1 SG Condition

Monitoring for 1R22 AND Final Operational Assessment for Cycles 23 & 24; 8/8/13

Drawings: 02-9124528D, Salem Unit 1 Steam Generator Channel Head Drain

Modification, Revision 001

Drawings: 1512E32, Salem REPLACEMENT Steam Generator General Layout; Salem

Unit 1 Steam Generator Channel Head Drain Modification, Revision 1

Drawing 02-9124526B, Revision 001, Steam Generator Channel Head Drain Plug

Document No.: 51-9207624-000, Salem Unit 1 SG Condition Monitoring for 1R22 and Final

Operational Assessment for Cycles 23 & 24

Other Documents

NRC Regulatory Issues Summary 2016-02, Design Basis Issues Related To Tube-To-

Tubesheet Joints in Pressurized-Water Reactor Steam Generators, March 23, 2016

PSEG NUCLEAR LLC VTD Number: 9000(019); AREVA Stress Analysis of Tube-Tubesheet

Weld-AREVA, Vendor Number 32-9235210-001

Section 1R11: Licensed Operator Requalification Program

Other Documents

SG-1624, Risk Management, SGFP Trip, SGTR, dated 05/21/16

Section 1R12: Maintenance Effectiveness

Procedures

ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Revision 14

Notifications

20689987 20729117* 20730512* 20730513* 20731038* 20732228*

Drawings

265029, Circ Water Swgr Bldg. 125VDC DC Distribution System, Revision 5

A-6

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Procedures

OP-AA-108-116, Protected Equipment Program, Revision 12

Notifications

20723781 20724495 20725030* 20725036 20726192 20727564

20727565 20728242 20731749 20733122

Maintenance Orders/Work Orders

60128649

Other Documents

ACE 20723873, 11 CFCU Low Speed Breaker Back-Flashed

Section 1R15: Operability Determinations and Functionality Assessments

Calculations, Analysis, Engineering Evaluations, and Specifications

MPR Associates Letter "Salem Service Water Discharge Header - Disposition of Degraded

Joints", (0108-0471-0007, Rev 1), 6/3/2016

MPR Associates Letter, Salem PCCP Bell-and-Spigot Joint Degradation-Supplemental

Information to (MPR-2650 Revision 0), 10/26/05

MPR Associates Letter, Salem Service Water Discharge Header - Disposition of Degraded

Joints (0108-0471-0007, Rev 0), 4/29/2016

MPR Calculation 0108-0333-JEM-01, Structural Evaluation of Service Water Piping Thinned

Joints, Revision 0

PSEG VTD 326511-001, "Structural Evaluation of Service Water Piping Thinned Joints"

PSEG VTD 326511-002, "Service Water

PSEG VTD 326511-003, "Service Water WEKO Seal Structural Repair Relief Request RAI

Response Technical Input"

PSEG VTD 326511-004, "Request for Use of Mechanical Repair System in Degraded Service

Water Pipe Joints - Input for Response to NRG Request for Additional Information dated

October 29, 2013"

S-C-SW-MEE-1975, Salem Units 1 & 2 Concrete Service Water Pipe Joints - Acceptance

Criteria, Revision 0

Drawings, Wiring Diagrams, and Piping and Instrumentation Diagrams

205243, Sheet 1, Auxiliary Building Control Air, Revision 49

0108-0471-0007, Salem Service Water Discharge Header - Disposition of Degraded Joints,

4/29/2016

Evaluations

70097092 70097514 70103845 70131286 70144770

Notifications

20724198 20726264 20727538 20727590 20726001

20726320 20727126 20727354 20727430 20727678

20729040 20730485* 20727242 20727261

A-7

Procedures

CC-AA-309-101, Engineering Technical Evaluation, Revision 10

OP-AA-108-115, Operability Determinations & Functionality Assessments, Revision 4

LS-AA-120, Issue Identification and Screening Process, Revision 13

LS-AA-125, Corrective Action Program, Revision 21

NO-AA-10, Quality Assurance Topical Report (QATR), Revision 84

S1.OP-PT.CA-0001, Emergency Control Air Compressor Functional Test, Revision 18

S1.OP-LR.CA-0005, Leak Rate Test 1CA920, Revision 1

SC.OP-LB.DF-0001, Diesel Fuel Oil Testing Program, Revision 3

Maintenance Orders/Work Orders

30265178 50140453 50154389 50154555 50158970 50172136

60115402

Miscellaneous

Inspection Manual Chapter 0326, Operability Determinations & Functionality Assessments for

Conditions Adverse to Quality or Safety, dated December 3, 2015

Event Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel

Internals, dated May 3, 2016

70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure,

Revision 0

70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure,

Revision 1

OpEval 2016-015, Potentially Degraded Baffle-Former Bolts in Salem Unit 2, Revision 0

80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0

80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1

S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,

Revision 0

S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,

Revision 1

80117136 SUP01, Map of Degraded Bolt Locations, Revision 0

Westinghouse LTR-RIDA-16-125, Rev. 2, Salem Unit 1 Baffle Bolting One Cycle Replacement

Pattern Summary Letter, dated May 31, 2016

WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2,

Revision 0

ML13093A382, Request for Relief from ASME Code Defect Removal for Service Water Buried

Piping, 4/3/2013

ML13227A338, PSEG Response to Request for Additional Information- Relief Request SC-14R-

133, Alternative Repair for Service Water System Piping, 8/15/13

ML14016A123, PSEG Response to Request for Additional Information (RAI 31 and RAI 32) -

Relief Request SC-14R-1 33, Alternative Repair for Service Water System Piping, 1/8/14

ML14058A228, PSEG Response to Request for Additional Information (RA133 - RAI36)-Relief

Request SC-14R-133, Alternative Repair for Service Water System Piping, 2/27/14

ML14085A482, PSEG Response to Request for Additional Information (RAJ 37) - Relief

Request SC-14R-133, Alternative Repair for Service Water System Piping, 3/26/14

ML14097A029, Salem Nuclear Generating Station, Units 1 And 2- Safety Evaluation of Relief

Request No. SC-14R-133 for the Alternative Repair for Service Water System Piping (TAC

NOS. MF1375 AND MF1376), 4/8/2014

A-8

Modifications

80110461

Other Documents

ML13093A382, Request for Relief from ASME Code Defect Removal for Service Water Buried

Piping, 4/3/2013

ML13227A338, PSEG Response to Request for Additional Information- Relief Request SC-14R-

133, Alternative Repair for Service Water System Piping, 8/15/13

ML14016A123, PSEG Response to Request for Additional Information (RAI 31 and RAI 32) -

Relief Request SC-14R-1 33, Alternative Repair for Service Water System Piping, 1/8/14

ML14058A228, PSEG Response to Request for Additional Information (RA133 - RAI36)-Relief

Request SC-14R-133, Alternative Repair for Service Water System Piping, 2/27/14

ML14085A482, PSEG Response to Request for Additional Information (RAJ 37) - Relief

Request SC-14R-133, Alternative Repair for Service Water System Piping, 3/26/14

ML14097A029, Salem Nuclear Generating Station, Units 1 And 2- Safety Evaluation of Relief

Request No. SC-14R-133 for the Alternative Repair for Service Water System Piping (TAC

NOS. MF1375 AND MF1376), 4/8/2014

Section 1R18: Plant Modifications

Condition Reports

20733528 20733526 20726264 20735142

Other Documents

80117136, Design Change Package for Salem Unit 1 Baffle-to-Former Bolt Replacement,

Revision 0

80117378, Item Equivalency Evaluation for Replacement Baffle Bolts, dated 6/2/2016

EVAL-16-19, Salem Unit 1 Baffle-Former Bolt Replacement 1R24, Revision 0

LTR-RIAM-16-39, Transmittal of Westinghouse Specification 70041 EB to PSEG, dated

5/4/2016

S2016-156, 50.59 Screening Form for DCP 80117136, Revision 0

WCAP-18144-P, Generic Replacement Type 316 Cold-Worked Baffle-Former Bolt Qualification

for 4-Loop Downflow Plants, Revision 0

Procedures

54-ISI-364-00, Remote Underwater In-Vessel Visual Inspection of Reactor Pressure Vessels,

Vessel Internals, and Components in Pressurized Water Reactors, dated August 22,

2000

54-ISI-372-005, Remote Underwater In-Vessel Visual Inspection of Baffle to Former Bolts and

Baffle Edge Bolts, dated September 23, 2011

54-UT-108-001, Ultrasonic Inspection of Internal Hex Head Baffle Bolts, dated April 24, 2011

GBRA 104650, Work Instruction Bolt Removal, Revision D

GBRA 173122, Repair and Inspection Sequence Plan for Baffle-former Bolt Replacement at

NPP Salem, Revision 00

A-9

Miscellaneous

180-9257342-000, NDE Services Final Report, Salem Unit 1, 1R24 Baffle to Former Plate Bolt

Inspection Report, dated June 2, 2016

51-9256526-000, Technical Justification for Internal Hex Head E Baffle to Former Bolts

Volumetric Examination at Westinghouse 4-Loop Reactors, dated April 25, 2016

IVVI-101, 01RF Examination Summary Record, VT-3 of Upper Core and Support Plate, dated

5/9/2001

Inservice Inspection Results, Bolt ID 5-55-C, dated May 3, 2016

Inservice Inspection Results, Bolt ID 6-75-C, dated April 30, 2016

NDE Personnel Qualification and Certification, VT-1, 2, & 3, Employee 16657, dated March 7,

2016

NDE Personnel Qualification and Certification, VT-1, 2, & 3, Employee 114882, dated March 4.

2015

MRP-228, Materials Reliability Program: Inspection Standard for PWR Internals- 2012 Update,

Revision 1

54-UT-108-001, Ultrasonic Inspection of Internal Hex Head Baffle Bolts, Revision 1

80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0

80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1

S2016-156, 50.59 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,

Revision 0

S2016-156, 50.59 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,

Revision 1

80117136 SUP01, Map of Degraded Bolt Locations, Revision 0

Westinghouse LTR-RIDA-16-125, Rev. 2, Salem Unit 1 Baffle Bolting One Cycle Replacement

Pattern Summary Letter, dated May 31, 2016

Westinghouse LTR-RIDA-16-125, Rev. 3, Salem Unit 1 Baffle Bolting One Cycle Replacement

Pattern Summary Letter, dated July 11, 2016

WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2,

Revision 0

WCAP-18144-P, Generic Replacement Type 316 Cold-Worked Baffle-Former Bolt Qualification

for 4-Loop Downflow Plants, Revision 0

VEN-16-041, Remote Visual Examination: Baffle-former Bolts (Core Side), dated July 27, 2016

Section 1R19: Post-Maintenance Testing

Procedures

SC.MD-PM.CBV-0002, CFCU Motor Heat Exchanger Internal Inspection, Revision 20

SC.MD-PM.SW-0012, Enecon Tubesheet Cladding System, Revision 13

SC.IC-TI.ZZ-0104, Configuration Control for NUS Model MTH801 Summators, Revision 32

S2.IC-CC.RCP-0058, 2FT-542 #24 Steam Generator Flow Protection Channel I, Revision 42

Notifications

20273570 20670175 20672463 20723478 20723652 20723765

20724185 20724217 20725095 20725111 20726481 20727534

Maintenance Orders/Work Orders

30205173 60120462 60128697 60129161

A-10

Evaluations

70171681

Section 1R20: Refueling and Other Outage Activities

Procedures

LS-AA-119-1003, Calculating Work Hours, Revision 7

MA-AA-716-008-1010, Reactor Services Project FME Plan, Revision 2

S1.OP-IO.ZZ-0006, Hot Standby to Cold Shutdown, Revision 37

S1.OP-TM.ZZ-0001, Reactor Coolant System Pressure - Temperature Curves, Revision 4

SC.OP-DL.ZZ-0001, Reactor Coolant System Heatup/Cooldown Log, Revision 9

SC.OP-DL.ZZ-00012, Pressurizer Heatup/Cooldown Log, Revision 5

Notifications

20723957 20725589* 20725843 20725856 20725917 20726061*

20726121 20726355 20727113 20727298 20727697 20729566

Other Documents

1R24 Shutdown Safety Evaluation and Approval, dated 03/25/16

Section 1R22: Surveillance Testing

Procedures

S2.OP-ST.RHR-0001, Inservice Testing - 21 Residual Heat Removal Pump, Revision 29

S2.RA-ST.RHR-0001, Inservice Testing 21 Residual Heat Removal Pump Acceptance Criteria,

Revision 12

S1.OP-ST.SSP-0001, Manual Safety Injection - SSPS, Revision 32

Notifications

20725279* 20725282* 20725581 20725603 20725936 20726147

20726148 20726342 20728892* 20728962* 20728963*

Maintenance Orders/Work Orders

50182657

Other Documents

Unit 1 Operator logs for April 17 and 18, 2016

Section 1EP6: Drill Evaluation

Procedures

NC.EP-EP.ZZ-0405, Emergency Termination - Redaction - Recovery, Revision

S2.OP-AB.Fuel-0001, Fuel Handling Incident, Revision 5

S2.OP-AB.CW-0001, Circulating Water System Malfunction, Revision 36

S2.OP-AB.CVC-0001, Loss of Charging, Revision 9

Notifications

20733529

20733001

A-11

Other Documents

S16-01, Salem All Facilities Training Drill, 06/16/16

Section 2RS1: Access Control to Radiologically Significant Areas

Procedures

RP-AA-301, Radiological Air Sampling Program, Revision 6

RP-AA-460, Control for High and Very High Radiation Areas, Revision 17

RP-AA-463, High Radiation Area Key Control, Revision 4

RP-AA-401-1001, Special Instruction for Highly Radioactive In-core Components, Revision 0

RP-SA-103, Radiological Control of Reactor Cavity and Spent Fuel Pool Operations, Revision 1

RP-AA-210, Dosimetry Issue, Usage, and Control, Revision 13

RP-AA-401, Operational ALARA Planning and Control, Revision 13

Other Documents

Audits

Locked High Radiation Key Inventory Logs

Radiation Protection Job Guides (7 through 14)

Radiological Survey data (various)

Radiation Protection Plant Radionuclide Evaluation

Corrective Action Documents (various Notifications)

Section 2RS2: Occupational ALARA Planning and Controls

Procedures

RP-AA-401, Operational ALARA Planning and Control, Revision 13

CY-AP-120-1030, Estimating RCS Crud Release for Refueling Outage, Revision 1

S1. CH-IO.ZZ-111(Z), Salem Unit 1 Shutdown Chemistry Plan, Revision 8

Other Documents

Refueling Outage Radiological Performance Report

ALARA Plans (various)

Radiation Protection Job Guides (7 through 14)

ALARA Work In-process Reviews

Outage Chemistry Control Plan

1R24 Hard Gamma Projection

Corrective Action Documents (various Notifications)

Section 2RS3: In-plant Airborne Radioactivity Control and Mitigation

Procedures

RP-SA-103, Radiological Control of Reactor Cavity and Spent Fuel Pool Operations, Revision 1

RP-AA-220, Annual Bioassay Review, Revision 9

RP-AA-301, Radiological Air Sampling Program, Revision 6

RP-AA-401, Operational ALARA Planning and Control, Revision 13

NF-AA-430, Failed Fuel Action Plan, Revision 8

A-12

Other Documents

Radiological Source Term Data - 10 CFR 61 waste stream report

Airborne Radioactivity Sampling Results (various)

Corrective Action Documents (various Notifications)

Section 2RS4: Occupational Dose Assessment

Procedures

RP-AA-401, Operational ALARA Planning and Control, Revision 13

Other Documents

Radiation Protection Job Guides (7 through 14)

General Source Term Data (various)

Corrective Action Documents (various notifications)

Section 2RS5: Radiation Monitoring Instrumentation

Procedures

RP-AA-301, Radiological Air Sampling Program, Revision 6

RP-AA-504, Routine Operation of the Radiation Protection Gross Counting facility

Other Documents

Instrument Source Check and Operability data (various)

Corrective Action Documents (various notifications)

Section 2RS7: Radiological Environmental Monitoring Program

Procedures

RP-AA-228, 10 CFR 50.75(g0 and 10 CFR 50.72.30(d) Documentation, Revision 3

EN-AA-170-500, Meteorological Monitoring System Calibration and Maintenance (Metrological

Tower), Revision 1

EN-AA-170-1000, Radiological Environmental Monitoring Program (REMP) and Meteorological

Program (MET) Implementation, Revision 1

EN-AA-1001, REMP Vendor Dosimetry and Laboratory QA Program

EN-AA-170-4000, Radiological Ground water Protection program Implementation, Revision 0

EN-AA-170-4160, Station RGPP Controlled sample Points, Revision 0

EN-AA-170-4200, Disposal of Water from Excavation projects, Revision 0

EN-AA0170-4300, Investigative Process for Evaluation of Anomalous Tritium Data from On-site

Wells, Revision 1

CY-AA-170-400, Radiological Ground water protection program, Revision 4

AD-LTS-10, Laboratory and Testing Service (LTS) Quality Assurance Program, Revision 4

Instruction NASSV-1.2.2NS, Service of Low Volume Sampler, Revision 19

Instruction MLKSA-1.1.2, Collection of Raw Milk samples, Revision 12

Instruction VGTSA-1.1.7, Collection of Vegetable, Vegetation and Fodder Crops, Revision 8

Instruction 1.1.9, Collection of Potable Water Samples, Revision 3

Instruction TLDSV-1.2.1, Installation of Area Monitoring Dosimeters in the Field, Revision 16

Instruction AQUACOLL-1.1.10, Collection of Aquatic samples, Revision 11

Instruction GMSA -1.1.11, Collection of Game samples, Revision 3

Instruction VEGECEN-0.3.2, Salem/Hope Creek Vegetable Garden Census, Revision 6

A-13

Instruction NRESCEN, Salem/Hope Creek Nearest Resident Census, Revision 5

Instruction MLKCEN 0.3.1, Salem/Hope Creek Census of Milk Animals, Revision 6

Instruction H2OSA-1.1.1, Collection of Water Samples, Revision 13

Instruction SOLSA -1.1.3, Collection of Soil Samples, Revision 8

Instruction ESS-1.1.5, Collection of Sediment Samples, Revision 9

Instruction ESFCH -1.1.6, Pickup of Fish and Crab Samples, Revision 7

Other Documents

Salem and Hope Creek Offsite Dose Calculation Manuals (ODCM)

UFSAR Section 11.6, Offsite Radiological Monitoring Program

Hope Creek Nuclear Station Buried and Underground Piping Asset Management Plan,

Revision 0

Salem and Hope Creek 2015 Annual Effluent Releases Reports

NEI-07-07, Structure, System, Component (SCC) Review for Turbine Roof Structure (Hope

Creek)

Salem and Hope Creek Annual Radiological Environmental Monitoring Reports

Salem/Hope Creek Meteorological Program Status Report (2014, 2015)

Salem/Hope Creek Metrological Tower Updated Vegetation Review, June 3, 2016

Comparison of 2015 Atmospheric Dispersion Factors for Salem and Hope Creek, dated

March 28, 2016

Chemistry, Radwaste, Effluent and Environmental Monitoring Audit Report, NOSA-SLM-16-04,

May 11, 2016

2016 Self-Assessment REMP Program Inspection

Teledyne Brown Environmental Service Annual Quality Assurance Report

GEL 2015 - Annual Quality Assurance Report (REMP)

Residential Survey, dated December 22, 2015

Milk Animal Survey dated December 2015

Vegetable garden Survey dated August 2015

Calibration Data (Dry Gas Meters 61182898, 14522708, 2424590)

Calibration Data (Laminar Flow Element 16300942)

Global Solutions Annual Testing, dated May 26, 2015

Passive Environmental Dosimetry Calibration data

Ground Water Monitoring Data and RGPP Data

Salem/Hope Creek Part 61 Analysis Review, dated April 27, 2016

Salem Remedial Action Plan Progress Reports

Corrective Action Documents (various Notifications)

Ground Water Monitoring Data

Corrective Action Documents (various Notifications)

Section 4OA2: Problem Identification and Resolution

Condition Reports

20724198 20726264 20727538 20727590 20728329 20732892

20731786 20725142 20736630

Maintenance Orders/Work Orders

70136205 70140618 70154315 70168067 70168874 70180750

70182469 70182519 70183590 70183629

A-14

Miscellaneous

Westinghouse LTR-RIDA-16-125, Rev. 2, Salem Unit 1 Baffle Bolting One Cycle Replacement

Pattern Summary Letter, dated May 31, 2016

Westinghouse LTR-RIDA-16-125, Rev. 3, Salem Unit 1 Baffle Bolting One Cycle Replacement

Pattern Summary Letter, dated July 11, 2016

WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2,

Revision 0

Non-Proprietary Safety Evaluation of WCAP-17096-NP, Revision 2, Reactor Internals

Acceptance Criteria Methodology and Data Requirements (TAC No. ME4200). (ADAMS

Accession No. ML16061A243), dated May 3, 2016

Westinghouse Calculation Note, CN-RIDA-15-34, Rev. 4, Units 1 and 2 Acceptable Baffle-

Former LOCA and Seismic Analysis, dated May 16, 2016

Westinghouse Calculation Note CN-RIDA-15-64, Rev. 2, Salem Units 1 and 2 Acceptable

Baffle-Former Bolting Pattern Fuel Grid Impact Analysis, dated May 16, 2016

Event Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel

Internals, dated May 3, 2016

80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 0

80117136, Salem Unit 1 Baffle to Former Bolt Replacement, Revision 1

S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,

Revision 0

S2016-156, 50.50 Screen: DCP 80117136, Salem Unit 1 Baffle to Former Bolt Replacement,

Revision 1

80117136 SUP01, Map of Degraded Bolt Locations, Revision 0

Westinghouse LTR-RIDA-16-112, Rev. 0, Summary of Salem Unit 1 Baffle-Former Bolt Real-

time Analysis Results, dated May 11, 2016

WCAP-18058-P, Determination of Acceptable Baffle-Former Bolting for Salem Units 1 and 2,

Revision 0

Westinghouse LTR-RIAM-16-38 Rev. 0, Salem Unit 1 Real-Time Analysis Results for

LOCA/Seismic Dynamic Analysis and Fuel Grid Impact Analysis, dated May 3, 2016

Westinghouse LTR-RIAM-16-39 Rev. 0, Transmittal of Westinghouse Specification 70041 EB to

Public Service Enterprise Group, dated May 4, 2016

Information Notice 98-11, Cracking of Reactor Vessel Internal Baffle-former Bolts in Foreign

Plants, dated March 24, 1998

Eval-16-19, Westinghouse Electric Company 10 CFR 50.59 Applicability Determination, Salem

Unit 1 Baffle-former Bole Replacement 1R24, Revision 0

MRP-228, Materials Reliability Program: Inspection Standard for PWR Internals - 2012 Update,

Revision 1

Unit 1 and 2 Technical Specifications, Revision 28

ACM 16-011, Baffle Plates Monitoring, dated June 17, 2016

ACM 16-011, Baffle Plates Monitoring, dated July 25, 2016

WCAP-15030-NP-A, Westinghouse Methodology for Evaluating the Acceptability of Baffle-

Former-Barrel Bolting Distributions Under Faulted Load Conditions, dated January 1999

NRC Safety Evaluation of Topical Report wCAP-25029, Westinghouse Methodology for

Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions Under Faulted

Load Conditions (TAC No. MA1152), dated November 16, 1998

NRC Letter, Leak Before Break Evaluation of Primary Loop Piping, Salem Nuclear Generating

Station, Units 1 and 2 (TAC NOS. M85799 and M85800), dated May 25, 1994

51-92566526, Technical Justification for Internal Hex Head E Baffle to Former Bolts Volumetric

Examination at Westinghouse 4-Loop Reactors, dated April 28 2016

A-15

54-ISI-364-00, IVVI Inspection Data Sheet Salem 1R14, dated May 8, 2001

Areva Letter, Completion and Status of Octants 1, 2, 3, 4, 5, 6, 7, and 8 (i.e., 1-8), dated May 5,

2016

OTDM 16-005, Salem Unit 2 Baffle to Former Bolting of Reactor Vessel Internals, dated June

16, 2016

WCAP-18144-P, Generic Replacement Type 316 Cold-Worked Baffle-Former Bolt Qualification

for 4-Loop Downflow Plants, Revision 0

Westinghouse LTR-LIS-11-381, LOCA Assessment of Core Coolable Geometry for Grid

Deformation in Peripheral Fuel Assemblies, dated June 27, 2011

Event Notification 51902, Anomalies Identified during Visual Inspection of Reactor Vessel

Internals, dated May 3, 2016

70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure,

Revision 0

70187161, Extent of Condition Review for Salem Unit 2 Susceptibility to Baffle Bolt Failure,

Revision 0

Op Eval 2016-015, Potentially Degraded Baffle-Former Bolts in Salem Unit 2, Revision 0

VEN-16-041, Remote Visual Examination Baffle-former Bolts (Core Side), dated July 27, 2016

Procedures

ER-AA-2003, System Performance Monitoring and Analysis, Revision 10

54-ISI-364-00, Remote Underwater In-Vessel Visual Inspection of Reactor Pressure Vessels,

Vessel Internals, and Components in Pressurized Water Reactors, dated August 22,

2000

54-UT-108-001, Ultrasonic Inspection of Internal Hex Head Baffle Bolts, dated April 28, 2016

Notifications

20704666 20706027 20709417 20710340* 20710947 20711723

20711796 20715617 20716352 20716358 20716401 20716402

20716404 20716754 20721375 20726684 20728492* 20730946

20734279* 20734280* 20734281* 20734284* 20734286* 20734856*

Other Documents

S2.OP-ST.SSP-0011(Q), Engineered Safety Features Response Time Testing performed

October 18, 2015

NRC Event Notification 51663

Exelon PowerLabs Report PSE-65422, 07/01/13

Exelon PowerLabs Report PSE-82817, 11/13/13

Exelon PowerLabs Report PSE-00915, 03/18/14

Exelon PowerLabs Report PSE-19717, 10/22/15

Exelon PowerLabs Report PSE-88030, Draft

Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion

Notifications

20733919*

A-16

LIST OF ACRONYMS

10 CFR Title 10 of the Code of Federal Regulations

AC alternating current

ACE apparent cause evaluation

ADAMS Agencywide Documents Access and Management System

AFW auxiliary feedwater

ALARA as low as is reasonably achievable

ASME American Society of Mechanical Engineers

AVR automatic voltage regulator

CAP Corrective Action Program

CCE common cause evaluation

CFCU containment fan cooling unit

CFR Code of Federal Regulations

CS containment spray

DC direct current

DCP design change package

EC eddy current

ECAC emergency compressed air compressor

ECCS Emergency Core Cooling System

ECT eddy current testing

EDG emergency diesel generator

EFPY effective full power years

EPD electronic personal dosimeter

EPRI Electric Power Research Institute

ESFAS engineered safety feature actuation system

FIN finding

FOSAR foreign object search and retrieval

GPI Groundwater Protection Initiative

HRA high radiation area

HSS high safety significant systems

HX heat exchanger

IMC Inspection Manual Chapter

IOD immediate operability determination

IR inspection report

ISI In-service inspection

IASCC Irradiation Assisted Stress Corrosion Cracking

kV kilovolt

LCO limiting conditions for operation

LER licensee event report

LHRA locked high radiation area

LLRT local leak rate test

LTS Laboratory and Testing Services

MPFF maintenance preventable functional failure(s)

MR maintenance rule

MRC Management Review Committee

NCV non-cited violation

NDE nondestructive examination

NEI Nuclear Energy Institute

A-17

NOS Nuclear Oversight

NOTF notification(s)

NRC Nuclear Regulatory Commission

NVLAP National Voluntary Laboratory Accreditation Program

ODCM Offsite Dose Calculation Manual

PC performance criteria

PI performance indicator(s)

PM preventive maintenance

PRA probabilistic risk assessment

PSEG Public Service Enterprise Group Nuclear LLC

QHPI Quick Human Performance Investigation

RCE root cause evaluation

RCS reactor coolant system

REMP Radiological Environmental Monitoring Program

RFO refueling outage

RG regulatory guide

RHR residual heat removal

RP radiation protection

RTO relay test order

RWP radiation work permit(s)

SBO station blackout

SDP significance determination process

SF spent fuel

SG steam generator

SI safety injection

SOC Station Oversight Committee

SSC structure, system, and component

SW service water

TS technical specification(s)

UFSAR Updated Final Safety Analysis Report

URI unresolved item

UT ultrasonically testing

V/Hz volt/hertz

VHRA very high radiation areas

WGE work group evaluation

WOs work order(s)

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