ML16266A224
ML16266A224 | |
Person / Time | |
---|---|
Site: | Salem |
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) | |
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
P.O. Box 236
Hancocks Bridge, NJ 08038
SUBJECT:
SALEM NUCLEAR GENERATING STATION, UNITS 1 AND 2 -
INTEGRATED INSPECTION REPORT 05000272/2016002 AND
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
w/Attachment: Supplementary Information
cc w/encl: Distribution via ListServ
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
1
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos.
50-272 and 50-311
License Nos.
Report Nos.
05000272/2016002 and 05000311/2016002
Licensee:
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
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.
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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.
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
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
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 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
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. 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
A-2
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Open 05000272/2016002-01
Baffle-Former Bolts with Identified
Anomalies (Section 1R08)
Open and Closed 05000311/2016002-02
Failure to Follow Operability
Determination Procedure for Unit 2
Baffle-Former Bolts (Section 1R15)05000311/2016002-03
Inadequate Work Order Planning Results in
Main Generator AVR STV Relay Trip
(Section 4OA3.3)
Closed
05000272:311/2015-008-01
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
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
alternating current
apparent cause evaluation
Agencywide Documents Access and Management System
as low as is reasonably achievable
American Society of Mechanical Engineers
Corrective Action Program
CCE
common cause evaluation
CFCU
containment fan cooling unit
CFR
Code of Federal Regulations
direct current
design change package
EC
eddy current
ECAC
emergency compressed air compressor
effective full power years
electronic personal dosimeter
Electric Power Research Institute
engineered safety feature actuation system
finding
FOSAR
foreign object search and retrieval
Groundwater Protection Initiative
high safety significant systems
heat exchanger
IMC
Inspection Manual Chapter
IOD
immediate operability determination
IR
inspection report
In-service inspection
Irradiation Assisted Stress Corrosion Cracking
kV
kilovolt
LCO
limiting conditions for operation
LER
licensee event report
local leak rate test
LTS
Laboratory and Testing Services
maintenance preventable functional failure(s)
maintenance rule
Management Review Committee
non-cited violation
NEI
Nuclear Energy Institute
A-17
NOS
Nuclear Oversight
NOTF
notification(s)
NRC
Nuclear Regulatory Commission
National Voluntary Laboratory Accreditation Program
Offsite Dose Calculation Manual
PC
performance criteria
performance indicator(s)
preventive maintenance
Public Service Enterprise Group Nuclear LLC
QHPI
Quick Human Performance Investigation
root cause evaluation
Radiological Environmental Monitoring Program
refueling outage
regulatory guide
radiation protection
RTO
relay test order
radiation work permit(s)
station blackout
significance determination process
SF
spent fuel
safety injection
Station Oversight Committee
structure, system, and component
TS
technical specification(s)
Updated Final Safety Analysis Report
unresolved item
ultrasonically testing
V/Hz
volt/hertz
very high radiation areas
WGE
work group evaluation
work order(s)