ML17319A152
| ML17319A152 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/14/2017 |
| From: | Fred Bower Reactor Projects Branch 3 |
| To: | Sena P Public Service Enterprise Group |
| References | |
| IR 2017003 | |
| Download: ML17319A152 (36) | |
See also: IR 05000272/2017003
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION I
2100 RENAISSANCE BLVD., SUITE 100
KING OF PRUSSIA, PA 19406-2713
November 14, 2017
Mr. Peter P. Sena, III
President and Chief Nuclear Officer
P.O. Box 236
Hancocks Bridge, NJ 08038
SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -
INTEGRATED INSPECTION REPORT 05000272/2017003 AND
Dear Mr. Sena:
On September 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at Salem Nuclear Generating Stations (Salem), Units 1 and 2. On October 10, 2017,
the NRC inspectors discussed the results of this inspection with Mr. Charles McFeaters, Salem
Vice President, and other members of your staff. The results of this inspection are documented
in the enclosed report.
NRC inspectors documented two findings of very low safety significance (Green) in this report.
Both of these findings involved violations of NRC requirements. Additionally, NRC inspectors
documented one Severity Level IV violation. The NRC is treating these violations as non-cited
violations (NCVs) consistent with Section 2.3.2.a of the Enforcement Policy.
If you contest the violations or significance of these NCVs, 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; and the
NRC Resident Inspector at Salem. In addition, if you disagree with a cross-cutting aspect
assignment in this report, you should provide a response within 30 days of the date of this
inspection report, with the basis for your disagreement, to the U. S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC, 20555-0001; with copies to the
Regional Administrator, Region I, and the NRC Resident Inspector at Salem.
P. Sena 2
This letter, its enclosure, and your response (if any) will be made available for public inspection
and copying at http://www.nrc.gov/reading-rm/adams.html and the NRC Public Document Room
in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.
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 05000272/2017003 and
w/Attachment: Supplementary Information
cc w/encl: Distribution via ListServ
SUNSI Review Non-Sensitive Publicly Available
Sensitive Non-Publicly Available
OFFICE RI/DRP RI/DRP RI/ORA 1R15* RI/DRP RI/DRP *
NAME PFinney RBarkley BBickett FBower RLorson
DATE 11/14/2017 10/24/2017 10/31/2017 11/14/2017 11/14/2017
- Section 1R15
1
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos. 50-272 and 50-311
License Nos. DPR-70 and DPR-75
Report Nos. 05000272/2017003 and 05000311/2017003
Licensee: PSEG Nuclear LLC (PSEG)
Facility: Salem Nuclear Generating Station, Units 1 and 2
Location: Hancocks Bridge, NJ 08038
Dates: July 1, 2017 through September 30, 2017
Inspectors: P. Finney, Senior Resident Inspector
A. Ziedonis, Resident Inspector
R. Barkley, Senior Project Engineer
T. Fish, Senior Operations Engineer
J. Furia, Senior Health Physicist
Approved By: Fred L. Bower, III, Chief
Reactor Projects Branch 3
Division of Reactor Projects
Enclosure
2
TABLE OF CONTENTS
SUMMARY ..3
REPORT DETAILS 5
1. REACTOR SAFETY .5
1R01 Adverse Weather Protection .................................................................................... 5
1R04 Equipment Alignment ............................................................................................... 6
1R05 Fire Protection .......................................................................................................... 7
1R11 Licensed Operator Requalification Program ............................................................ 7
1R12 Maintenance Effectiveness ...................................................................................... 8
1R13 Maintenance Risk Assessments and Emergent Work Control ................................. 8
1R15 Operability Determinations and Functionality Assessments ..................................... 9
1R18 Plant Modifications .................................................................................................15
1R19 Post-Maintenance Testing .......................................................................................15
1R22 Surveillance Testing ...............................................................................................16
2. RADIATION SAFETY ........................................................................................................18
2RS2 Occupational ALARA Planning and Controls ...................................................................18
2RS6 Radioactive Gaseous and Liquid Effluent Treatment ....................................................19
4. OTHER ACTIVITIES .....................20
4OA1 Performance Indicator Verification ..........................................................................20
4OA2 Problem Identification and Resolution .....................................................................21
4OA6 Meetings, Including Exit...........................................................................................21
ATTACHMENT: SUPPLEMENTARY INFORMATION ..21
SUPPLEMENTARY INFORMATION....................................................................................... A-1
KEY POINTS OF CONTACT .................................................................................................. A-1
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED .................................... A-1
LIST OF DOCUMENTS REVIEWED....................................................................................... A-1
LIST OF ACRONYMS ........................................................................................................... A-11
3
SUMMARY
Inspection Report (IR) 05000272/2017003, 05000311/2017003; 07/01/2017 - 09/30/2017;
Salem Nuclear Generating Station Units 1 and 2; Operability Determinations and Functionality
Assessments; Surveillance Testing.
This report covered a three-month period of inspection by resident inspectors and announced
inspections performed by regional inspectors. The inspectors identified one NRC-identified
finding and one self-revealing finding of very low safety significance (Green). The inspectors
also identified one Severity Level IV violation. All three findings were non-cited violations
(NCVs). 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 November 1, 2016. The NRCs program for overseeing the safe operation of
commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 6.
Cornerstone: Mitigating Systems
- Severity Level IV. Inspectors identified a Severity Level IV (SLIV) non-cited violation (NCV)
of Title 10 of the Code of Federal Regulations (10 CFR) 50.55a(z) when a periodic Inservice
Test (IST) of the 14 service water (SW) pump and its strainer outlet check valve was not
completed prior to expiration of its testing frequency on August 4 without Nuclear Reactor
Regulation (NRR) authorization. PSEGs corrective actions (C/As) included making repairs
to the 14 SW strainer, satisfactory completion of the 14 SW IST on August 21, chartering an
apparent cause evaluation (ACE), and entering the issue in their Corrective Action Program
(CAP) as notification (NOTF) 20772390.
The issue was assessed in accordance with IMC 0612 and traditional enforcement applied
since the issue impeded the regulatory process. Specifically, PSEG did not perform the
prescribed IST or obtain prior NRR authorization for an alternative measure in accordance
with 10 CFR 50.55(a)(z). The Reactor Oversight Processs (ROP) significance
determination process does not specifically consider regulatory process impact in its
assessment of licensee performance. Therefore, it was necessary to address this violation,
which impeded the NRCs ability to regulate, using traditional enforcement to adequately
assess the non-compliance. The violation was determined to be a SLIV since: 1) the delay
in the inservice test required, and PSEG did not obtain, prior Commission review and
approval, 2) the associated consequence was minor or of very low safety significance, and
3) the NRC would have likely approved an alternative, given reasonable assurance of
operability of the 14 SW train, in accordance with Section 6.1 of the NRC Enforcement
Policy. The NRC also determined this violation was associated with a minor ROP
performance deficiency. Traditional enforcement violations are not assessed for
cross-cutting aspects. (Section 1R15)
4
Cornerstone: Barrier Integrity
- Green. The inspectors identified a Green non-cited violation (NCV) of Technical
Specifications (TS) Limiting Condition for Operation (LCO) 3.6.1.1, Containment Integrity,
when PSEG did not ensure that the APD backup CIVs, associated with penetrations
required to be closed during accident conditions, were unisolated intermittently under
appropriate administrative controls. Specifically, manual CIVs associated with the APD
sampling system were opened and left continuously open for 27 days, under tagging
instructions that would have resulted in an actual open penetration outside of containment
during certain design basis accidents and PSEG had not evaluated the adequacy of the
tagging instruction to ensure radiological dose consequences would remain in conformance
with the licensing basis. PSEG entered this issue in the Corrective Action Program (CAP)
as notifications (NOTFs) 20751423 and 20777663. Technical Specification (TS) compliance
was restored on January 4, 2017, when PSEG restored the normal air APD sample valve
configuration.
This issue was more than minor since it was associated with the configuration control
attribute of the Barrier Integrity cornerstone and adversely impacted its objective to provide
reasonable assurance that physical design barriers (containment) protect the public from
radionuclide release cause by accidents or events. Using Appendix H, the inspectors
determined this finding was of very low safety significance, or Green, because this was a
Type B finding (Section 4.0), involving small diameter lines that were not important to large
early release frequency (LERF), as described in Table 4.1. The finding had a cross-cutting
aspect in the area of Human Performance, Work Management, in that the organization
implements a process of planning, controlling, and executing work activities such that
nuclear safety is the overriding priority. Specifically, the planned tagging instructions for
control of the back-up sampling valves did not ensure the work activity was controlled and
executed in accordance with TS. [H.5] (Section 1R15)
- Green. A self-revealing Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs, as described in Regulatory Guide 1.33, Revision 2,
was identified because PSEG did not install the 12 service water (SW) accumulator
injection check valve (12SW536) in accordance with written procedures. Specifically, the
check valve was installed in the wrong orientation, which impacted the ability of the valve to
close and support containment integrity. PSEG entered this issue in the Corrective Action
Program (CAP) as notifications (NOTFs) 20771353 and 20776321, and performed
Equipment Reliability Evaluation (ERE) 70195309. Corrective actions (C/As) consisted of
removing the check valve from the system, clearing the silt build-up, and reinstalling the
check valve in the correct orientation.
This issue was more than minor since it was associated with the configuration control
attribute of the Barrier Integrity Cornerstone and adversely impacted its objective to provide
reasonable assurance that physical design barriers (containment) protect the public from
radionuclide releases cause by accidents or events. Using IMC 0609, Attachment 4 and
Appendix A, Exhibit 3, the inspectors determined that this finding was of very low safety
significance, or Green, because the finding did not result in an actual open pathway in the
physical integrity of reactor containment. The inspectors determined there was no
cross-cutting aspect associated with this finding because the causal factors associated with
this finding occurred outside the nominal three-year period of consideration and were not
considered representative of present performance, in accordance with IMC 0612.
(Section 1R22)
5
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at 100 percent rated thermal power (RTP). The unit
remained at or near 100 percent RTP for the remainder of the inspection period.
Unit 2 began the inspection period at 100 percent RTP. On September 2, the unit made an
unplanned power reduction to approximately 15 percent RTP in support of stator water cooling
corrective maintenance. The unit returned to 100 percent RTP on September 5. The unit
remained at or near 100 percent RTP for the remainder of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01 - 3 samples)
.1 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
During the week of August 28, inspectors performed a review of PSEGs readiness for
the hurricane season. The review focused on the service water intake structure (SWIS),
the circulating water intake structure, and auxiliary building penetrations. The inspectors
reviewed the Updated Final Safety Analysis Report (UFSAR), technical specifications
(TSs), control room logs, and the CAP to determine what temperatures or other
seasonal weather could challenge these systems, and to ensure PSEG personnel had
adequately prepared for these challenges. The inspectors reviewed station procedures,
including PSEGs seasonal weather preparation procedure and applicable operating
procedures. The inspectors performed walkdowns of the selected systems to ensure
station personnel identified issues that could challenge the operability of the systems
during hurricane conditions. Documents reviewed for each section of this inspection
report are listed in the Attachment.
b. Findings
No findings were identified.
.2 Readiness for Impending Adverse Weather Conditions
a. Inspection Scope
The inspectors reviewed PSEGs preparations for the onset of hot weather on July 20.
The inspectors reviewed the implementation of adverse weather preparation procedures
before the onset of and during this adverse weather condition. The inspectors walked
down the emergency diesel generators (EDGs) and SWIS to ensure system availability.
The inspectors verified that operator actions defined in PSEGs adverse weather
procedure maintained the readiness of essential systems. The inspectors discussed
readiness and staff availability for adverse weather response with operations and work
control personnel.
6
b. Findings
No findings were identified
.3 External Flooding
a. Inspection Scope
During the week of July 5, the inspectors performed an inspection of the external flood
protection measures for Salem Unit 1 and Unit 2. The inspectors reviewed TSs,
procedures, design documents, and the UFSAR, which depicted the design flood levels
and protection areas containing safety-related equipment to identify areas that may be
affected by external flooding. The inspectors conducted a general site walkdown of all
external areas of the plant, including the EDG annex, turbine building basement and SW
vaults to ensure that PSEG erected flood protection measures in accordance with design
specifications. Where applicable the inspectors determined the installed flood seal
service life and verified that adequate procedures existed for inspecting the installed
seals. The inspectors also reviewed operating procedures for mitigating external
flooding, to confirm that, overall, PSEG had established adequate measures to protect
against external flooding events and, more specifically, that credited operator actions
were adequate.
b. Findings
No findings were identified.
1R04 Equipment Alignment
Partial System Walkdown (71111.04Q - 3 samples)
a. Inspection Scope
The inspectors performed partial walkdowns of the following systems:
- Common, Single offsite power source during bus Section 2 maintenance on
September 20
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 UFSAR, TSs, work orders
(WOs), 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.
7
b. Findings
No findings were identified.
1R05 Fire Protection
Resident Inspector Quarterly Walkdowns (71111.05Q - 4 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 OOS, degraded, or
inoperable fire protection equipment, as applicable, in accordance with procedures.
- Unit 2, SWIS on July 17
- Unit 2, Charging pump and spray additive tank area on July 25
- Common, Turbine building basement on July 6
b. Findings
No findings were identified.
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 August 29, which
included a condenser tube leak, small break and large break loss of coolant accidents,
pressurizer instrument failure, condensate pump trip, main steam line leak, and multiple
faulted steam generators. The inspectors evaluated operator performance during the
simulated events 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.
8
1R12 Maintenance Effectiveness (71111.12Q - 2 samples)
a. Inspection Scope
The inspectors reviewed the samples listed below to assess the effectiveness of
maintenance activities on structure, system, and component (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 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 C/As 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 1, SW pump strainers on July 27
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 4 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, Fire in (a)(4) risk with 16 SW pump unavailable on September 6
- Unit 2, Emergent unavailability of 2B EDG on July 10
b. Findings
No findings were identified.
9
1R15 Operability Determinations and Functionality Assessments (71111.15 - 7 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, 12 containment fan cooling unit (CFCU) degraded motor megger and failure
to start in high speed on July 19
- Unit 1, Containment isolation valves for air particulate detector back-up sampling on
August 3
- Unit 2, 2B EDG following K1C relay failure on July 12
- Unit 2, Containment with outer equipment hatch removed on August 31
September 27
- Common, Functionality of seismic trigger during instrument maintenance activity on
September 26
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.
b. Findings
.1 Expiration of Periodic Inservice Testing of 14 Service Water Pump
Introduction. Inspectors identified a SLIV NCV of 10 CFR 50.55a(z) when a periodic IST
of the 14 SW pump and its strainer outlet check valve was not completed prior to
expiration of its testing frequency without NRR authorization.
Description. The Salem Unit 1 SW system consists of two trains of three pumps each in
independent compartments that are valved into one of two independent supply headers.
Each SW pump discharges to its own automatic, self-cleaning strainer and check valve
prior to entering the compartment supply header. Title 10 CFR 50.55(a)(f)(4) requires
that pumps and valves that are classified as American Society of Mechanical Engineers
(ASME) Code Class 1, 2, and 3 must meet the IST requirements set forth in the ASME
Operation and Maintenance (OM) code and addenda to the extent practical. Since the
SW pumps and their strainer outlet check valves are ASME Code Class 3, they are
subject to the ASME OM code and the associated periodic testing. Salems ASME OM
Code version of applicability is ASME OM Code-2001 through the ASME OMb
Code-2003 Addenda. Tables ISTB-3400-1 and ISTC-3500-1 respectively establish a
quarterly IST frequency for Group A pumps and Category C check valves, such as the
14 SW pump and its strainer outlet check valve.
10
On April 11, 2017, an IST of 14 SW was completed. Based on a 92-day test interval, the
next quarterly nominal due date was July 12. On July 16, during the subsequent 14 SW
IST, the pump strainer differential pressure (D/P) would not lower sufficiently to allow the
strainer backwash cycle to stop. The IST data is invalidated with the strainer in
backwash and the IST could not be completed. Operators performed a backflush of the
strainer which lowered D/P and stopped the backwash cycle, but the strainer backwash
recommenced during a subsequent IST attempt. PSEG documented (NOTF 2077137)
this condition and acknowledged that the IST would go overdue on August 4 given
application of a 25 percent grace period allowed by ASME OMN-20. PSEG determined,
via discussions with the vendor that had refurbished the strainer, and documented in the
same NOTF on July 18, that the strainer element was likely improperly assembled with
its filter media elements installed backwards. On August 3, PSEG wrote NOTF
20772751 regarding the continued inability to perform the 14 SW pump IST and
requested an Operability Evaluation (OpEval) to support continued operation for the 14
SW pump being in a condition that is Operable but Nonconforming to an ASME
commitment. In the associated OpEval 17-006 (operation 70195617), PSEG determined
that the 14 SW pump remained operable given reasonable assurance in procedures and
calculations that the SW pump was able to perform its safety function with the strainer in
continuous backwash. Additionally, in the OpEval, PSEG documented its decision to not
perform the 14 SW pump and 14 SW check valve (14SW2) IST based on a
determination that, although not performing the IST would be in noncompliance with the
ASME code, it would not be a violation of regulatory requirements, since PSEG
concluded the test was not required by site TSs. On August 8, PSEG documented NRC
resident inspector questions regarding not performing the 14 SW IST (NOTF 20772390).
As part of their assessment, the inspectors reviewed PSEGs IST program and other
licensing documents. On August 30, 2016, PSEG submitted a license amendment
request (ML16243A233) in accordance with 10 CFR 50.55a(z), that proposed an
alternative to the testing frequencies in the ASME OM Code by adopting Code Case
OMN-20. Code Case OMN-20, Inservice Test Frequency, allowed test frequency
grace to be applied to ASME OM test frequencies. In particular, quarterly tests were
established with periods of 92 days and that the period may be extended by up to
25 percent for any given test. On May 19, 2017, the NRC issued its Safety Evaluation
Report and approved the relief request (ML17132A005) to adopt ASME Code Case
Through discussions with both PSEG and NRC Regional and NRR staff, the inspectors
concluded that while operators had appropriately assessed that the 14 SW pump
remained operable given the strainer condition, PSEG had incorrectly determined that
IST performance could be delayed beyond the overdue date without violating regulatory
requirements. The inspectors conclusion was based not only on the guidance in the
ASME OM Code and OMN-20, but also on review of PSEGs OpEval. In particular,
PSEGs OpEval referenced EGM 12-001, Dispositioning Noncompliance with
Administrative Controls Technical Specifications Programmatic Requirements that
Extend Test Frequencies and Allow Performance of Missed Tests (ML11258A243),
where the NRC stated that it would exercise enforcement discretion to allow application
of Surveillance Requirement (SR) applicability to TS administrative controls and licensee
noncompliance with the IST program as described in the Administrative Controls section
of TSs. However, EGM 12-001 was not appropriately applied in this case because the
SW system IST requirement does not reside in the associated TS SRs, the IST was not
performed as opposed to discovered after the fact as a missed test, and EGM 12-001
11
expired upon the NRCs disposition of PSEGs license amendment request as described
within its own guidance when Amendment No. 319 was issued on June 28, 2017
(ML17165A214). The inspectors further noted that 10 CFR 50.55(a)(a) requires that
proposed alternatives to ASME IST testing requirements must be submitted to NRR, and
are required to be authorized prior to implementation. The inspectors determined that in
lieu of performing repairs to the 14 SW strainer and successfully completing the IST
within the required grace period, PSEG would have been required to obtain prior
authorization for alternative testing of the 14 SW IST components under 10 CFR 50.55(a)(z), instead of allowing the test to expire. PSEGs C/As included completing 14
SW strainer repairs, satisfactory completion of the 14 SW IST on August 21, and
chartering an apparent cause evaluation (ACE).
Analysis. Not performing the 14 SW IST or obtaining prior authorization for an
alternative in accordance with 10 CFR 50.55(a)(z) was a performance deficiency within
PSEGs ability to foresee and correct. The issue was assessed in accordance with IMC 0612 and traditional enforcement applied since the issue impeded the regulatory
process. Specifically, PSEG did not perform the prescribed IST or obtain prior
authorization for an alternative in accordance with guidance in 10 CFR 50.55a. The
ROPs significance determination process does not specifically consider regulatory
process impact in its assessment of licensee performance. Therefore, it was necessary
to address this violation, which impeded the NRCs ability to regulate, using traditional
enforcement to assess the non-compliance.
The violation was determined to be a SLIV in accordance with Section 6.1 of the
Enforcement Policy since the associated consequence was minor or of very low safety
significance, and the NRC would have likely approved an alternative test interval given
reasonable assurance of operability of the 14 SW train. In accordance with IMC 0612,
the NRC also determined this violation was associated with a minor ROP performance
deficiency. Traditional enforcement violations are not assessed for cross-cutting
aspects.
Enforcement. Title 10 CFR 50.54, establishes that the applicable requirements of
10 CFR 50.55a are conditions in every nuclear power reactor operating license. Title
10 CFR 50.55a(z) requires, in part, that alternatives to the requirements of 10 CFR 50.55a(f) may be used when authorized by the NRC and that the proposed alternative
must be submitted and authorized prior to implementation. Title 10 CFR 50.55a(f)
requires, in part, that systems and components of water-cooled nuclear power reactors
must meet the requirements of ASME OM Code. ASME OM Code-2001, Tables
ISTB-3400-1 and ISTC-3500-1, respectively, establish a quarterly IST frequency for
Group A pumps and Category C check valves, such as the 14 SW pump and its strainer
outlet valve. ASME Code Case OMN-20 allows test frequency grace periods of up to
25 percent for quarterly tests with periods established at 92 days. Contrary to the
above, from August 4 to August 21, 2017, PSEG implemented an alternative to the
ASME OM Code without first obtaining authorization from the NRC. Specifically, PSEG
did not perform the 14 SW quarterly IST in accordance with test requirements within the
92 day period (July 12) plus the 25 percent grace period (August 4) and did not submit
and obtain prior NRC authorization for this alternative measure. PSEG subsequently
completed the 14 SW IST on August 21 and captured the issue in their CAP as
NOTF 20772390. Since the issue was of minor or very low safety significance and
was entered into PSEGs CAP, this violation is being treated as an NCV, consistent
12
with Section 2.3.2.a of the Enforcement Policy. (NCV 05000272/2017003-01,
Expiration of Periodic Inservice Testing of 14 Service Water Pump)
.2 Violation of Containment Integrity Technical Specification
Introduction. The inspectors identified a Green NCV of TSs LCO 3.6.1.1, Containment
Integrity, when PSEG did not ensure that the APD backup CIVs, associated with
penetrations required to be closed during accident conditions, were unisolated
intermittently under appropriate administrative controls. Specifically, manual CIVs
associated with the APD sampling system were opened and left continuously open for
27 days, under tagging instructions that would have resulted in an actual open
penetration outside of containment during certain design basis accidents and PSEG had
not evaluated the adequacy of the tagging instruction to ensure radiological dose
consequences would remain in conformance with the licensing basis.
Description. On December 8, 2016, PSEG closed two normally open inboard (1VC7 and
1VC11) and outboard (1VC8 and 1VC12) automatic CIVs associated with the Unit 1
containment APD one-inch diameter containment penetrations, which are open to the
containment atmosphere and pass to the APD sampling detector outside of containment.
The control power breaker associated with the automatic APD CIVs was opened under
tagging instruction 4402568 to support planned maintenance to replace a control area
radiation monitor (1-R1A). With the automatic APD CIVs closed, tagging instruction
4402568, and operator turnover notes, directed PSEG operators to open two normally
closed inboard (1VC9 and 1VC13) and outboard (1VC10 and 1VC14) backup APD
remote manual CIVs.
On December 12, 2016, the inspectors questioned PSEG operators regarding the basis
for operability of the backup APD CIVs, given that remote manual closure, using
pushbutton(s) in the main control room, would be required to ensure the safety function
was met during a design basis accident. PSEG operators cited procedure
OP-AA-108-115, Operability Determinations and Functionality Assessments, Revision
4, Section 4.15, Use of Manual Actions in Place of Automatic Actions, as the basis for
operability. PSEG operators stated that one of two licensed operators at the controls
was credited to close the remote manual CIVs from the control room, in accordance with
tagging instruction 4402568, and step 10 of Emergency Operating Procedure (EOP)
1-EOP-TRIP-1, Reactor Trip or Safety Injection, Revision 31. The inspectors
evaluated the EOP to assess whether the planned manual action would be consistent
with the applicable licensing and design bases analyses. The inspectors observed that
1-EOP-TRIP-1, step 10, was not a continuous action step. The inspectors further
questioned whether the timing of the manual actions, and associated dose
consequence, had been evaluated prior to implementation of the tagging instructions.
PSEG operators stated that the maintenance activity was pre-planned as part of the
work control process, and the manual controls were adequate. PSEG operators
captured the inspectors question in NOTF 20751423. When the inspectors questioned
PSEG operations management as to whether any additional controls or evaluation were
warranted to ensure CIV operability during the planned maintenance activity, PSEG
re-stated that the existing controls were adequate, and the inspectors question would be
addressed through the CAP.
On January 4, 2017, PSEG completed the 1-R1A replacement, and restored the normal
APD valve configuration. On May 12, PSEG provided the inspectors with Technical
13
Evaluation (TE) 70191433 that evaluated the radiological consequences of operating
with backup APD CIVs opened under tagging instruction 4402568. The TE determined
the increase in radiological dose was insignificant with respect to the previously
analyzed values in UFSAR Table 15.4-5C, Loss of Coolant Accident (LOCA) Dose
Consequences. Specifically, the TE concluded the most limiting consequence was for
the main control room dose, and determined there would be less than a 0.01 rem
increase to the previously analyzed value of 4.3 rem.
The inspectors concluded the TE was inadequate, primarily because the TE incorrectly
assumed the CIVs would be remotely isolated prior to the onset of fuel damage.
Specifically, the TE assumed no fuel damage for the first 10 minutes of the accident.
However, the inspectors noted the Salem licensing basis was previously reviewed and
approved by the NRC with an assumed onset of fuel damage at 30 seconds, in
accordance with the NRC Safety Evaluation Report associated with the Alternate Source
Term License Amendment (ML060040322), as well as station calculation
S-C-ZZ-MDC-1945, Post-LOCA Doses - Alternate Source Term (AST), Revision 4.
The inspectors determined that PSEGs non-conservative time assumption (10 minutes
versus 30 seconds) prior to the onset of fuel damage, had a direct correlation to the
postulated dose consequences. Specifically, the TE determined that for the most
limiting accident, the containment atmosphere would be released into the Auxiliary
Building in approximately 10 seconds, due to containment pressure exceeding the APD
sample skid rating of 15 psig. The inspectors further noted the TE assumed the backup
APD sample valves would be closed in accordance with the EOPs in approximately 8
minutes, based on previous timed evaluation of a separate step in 1-EOP-TRIP-1,
OP-SA-102-106-F1, Master List of Times Actions, Revision 1. However, the inspectors
determined that the master list of timed actions did not fully evaluate the time required to
isolate CIVs; for example, it did not account for certain conditions in 1-EOP-TRIP-1 that
could direct Operators to other EOPs prior to isolating the CIVs in step 10.
The inspectors reviewed TS LCOs 3.6.1.1, Containment Integrity, and 3.6.3.1,
Containment Isolation Valves. TS LCO 3.6.1.1 states that primary CONTAINMENT
INTEGRITY shall be maintained. TS 1.7 defines CONTAINMENT INTEGRITY as all
penetrations required to be closed during accident conditions are either capable of being
closed automatically, or otherwise secured in their closed position, except as permitted
by TS 3.6.3.1. TS LCO 3.6.3.1 states that each containment isolation valve shall be
OPERABLE, and the action statements are modified by Note 1, which states that
penetration flow paths, except for the containment purge valves, may be unisolated
intermittently under administrative controls. Since Note 1 modifies the LCO 3.6.3.1
action statements, entry into an action statement would be required to invoke Note 1.
However, the inspectors identified that PSEG never entered a TS LCO 3.6.3.1 action
statement to apply administrative controls when the backup APD manual valves were
opened on December 8, 2016. The inspectors also reviewed the UFSAR Table 6.2-10,
and noted the list of CIVs is contained in the Technical Requirements Manual (TRM).
TRM Table 3.6-1 classifies the APD back-up sample valves as remote manual
containment isolation valves. UFSAR Section 6.2.4.3, item 3, states manual
containment isolation valves are operated under administrative control. UFSAR accident
analysis Sections 15.4.1.8 and 15.4.1.9 discuss the alternate source term analysis
results for the most limiting loss of coolant accident. Based on a review of the TS,
UFSAR, TRM, and TE 70191433, the inspectors concluded that PSEGs use of tagging
instruction 4402568 to control opening manual CIVs continuously for 27 days was not in
compliance with TSs, because the backup APD manual valves were not opened
14
intermittently, and the administrative controls were not adequate to ensure the
radiological dose consequences would remain in conformance with the licensing basis.
Analysis. The inspectors determined there was a performance deficiency that was
within PSEGs ability to foresee and correct. Specifically, TS 3.6.1.1 requires manual
containment isolation valves to be secured in their closed position, or opened
intermittently under administrative control as permitted by TS 3.6.3.1; however, the
containment APD backup sampling manual CIVs were opened continuously for 27 days
under administrative controls that were not properly reviewed and determined to be
adequate under accident conditions. This issue was more than minor since it was
associated with the configuration control attribute of the Barrier Integrity cornerstone and
adversely impacted its objective to provide reasonable assurance that physical design
barriers (containment) protect the public from radionuclide release cause by accidents or
events. Specifically, containment isolation valves were opened continuously for 27 days,
contrary to TS, and would have resulted in an actual open pathway outside of
containment during certain design basis accidents. Using IMC 0609, Attachment 4 and
Appendix A, Exhibit 3, this finding was required to be screened in accordance with IMC 0609, Appendix H, Containment Integrity Significance Determination Process. Using
Appendix H, the inspectors determined this finding was of very low safety significance,
or Green, because this was a Type B finding (Section 4.0), involving small diameter lines
that were not important to LERF, as described in Table 4.1.
The finding had a cross-cutting aspect in the area of Human Performance, Work
Management, in that the organization implements a process of planning, controlling, and
executing work activities such that nuclear safety is the overriding priority. Specifically,
the planned tagging instructions for control of the back-up sampling valves did not
ensure the work activity was controlled and executed in accordance with TS. [H.5]
Enforcement. Technical Specification LCO 3.6.1.1 action statement requires that
without primary containment integrity, restore containment integrity within one hour or be
in at least Mode 3 within the next six hours and Mode 5 within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
TS 1.7 defines CONTAINMENT INTEGRITY as all penetrations required to be closed
during accident conditions are either capable of being closed automatically, or otherwise
closed by manual valves, except for valves that are open under administrative control as
permitted by TS 3.6.3.1.
Technical Specification 3.6.3.1, action 1, requires that with one or more containment
isolation valves inoperable, maintain at least one isolation valve operable in each
affected penetration that is open, and within four hours either restore the inoperable
valve(s) or isolate the affected penetration, or be in at least Mode 3 within the next six
hours and in Mode 5 within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Action 1 is modified by note 1, which
states penetration flow paths, except for the containment purge valves, may be
unisolated intermittently under administrative controls.
Contrary to the above, from December 8, 2016, to January 4, 2017, PSEG did not
ensure that the APD backup CIVs, associated with penetrations required to be closed
during accident conditions, were unisolated intermittently under appropriate
administrative controls. Specifically, the CIVs were opened continuously for this 27 day
period, without entry into LCO action 3.6.3.1, action 1. Additionally, the administrative
controls applied consisted of a tagging instruction and turnover note for one of the two
licensed operators at the controls to remotely close the CIVs from the control room in
15
accordance with an EOP. The valve configuration would have resulted in an actual open
pathway outside of containment during design basis accidents; however, PSEG had not
evaluated the adequacy of the tagging instruction to ensure radiological dose
consequences would remain in conformance with the licensing basis. PSEG entered
this issue in the CAP as NOTFs 20751423 and 20777663. TS compliance was restored
on January 4, 2017, when PSEG restored the normal APD sample valve configuration.
Because this violation was of very low safety significance (Green), and was entered into
PSEGs CAP, this issue is being treated as an NCV consistent with Section 2.3.2.a of
the Enforcement Policy. (NCV 05000272/2017003-02, Violation of Containment
Integrity Technical Specification)
1R18 Plant Modifications (71111.18 - 1 sample)
a. Inspection Scope
The inspectors reviewed the temporary modifications listed below to determine whether
the modifications affected the safety functions of systems that are important to safety.
The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing
results, and conducted field walkdowns of the modifications to verify that the temporary
modifications did not degrade the design bases, licensing bases, and performance
capability of the affected systems.
- Unit 2, 22 SW pump stiffeners on August 24
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing (71111.19 - 5 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 points were performed and checked, and
that results adequately demonstrated restoration of the affected safety functions.
- Unit 1, SW bearing cooling supply restricted orifice leak repair on July 31
- Unit 1, 12 Chilled water pump trip on September 18
- Unit 1, 11 ABV supply fan motor failure on September 27
- Unit 2, 23 Delta-T T-average deviation on September 14
16
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
supported that equipment was capable of performing the required safety functions. The
inspectors reviewed the following surveillance tests:
- Unit 1, SW accumulator check valve, 12SW536, (IST) on July 14
- Unit 1, 11 Containment spray flow test (IST) on August 2
- Unit 1, 1C EDG endurance run on September 12
b. Findings
Introduction. A self-revealing Green NCV of TS 6.8.1, Procedures and Programs, as
described in Regulatory Guide 1.33, Revision 2, was identified because PSEGs
installation of the 12 SW accumulator injection check valve (12SW536) was not in
accordance with written procedures. Specifically, the check valve was installed in the
wrong orientation, which impacted the ability of the valve to close and support
containment integrity.
Description. The 12SW536 check valve has a safety function to open in the injection
flow path from the 12 SW accumulator tank to the portion of the SW header that supplies
the 14 and 15 CFCUs inside primary containment. The SW accumulator tanks have a
design function to rapidly inject water into the SW system, keep the system full, and
prevent a water hammer phenomena following any accident or event with a loss of
off-site power (LOOP) due to the stopping and re-starting the vital bus-powered SW
pumps. The 12SW536 also has a safety function to close following accumulator
injection, to prevent reverse flow of SW from the 14 and 15 CFCU supply line back into
the 12 accumulator tank. The 12SW536 is a dual-plate, wafer-style check valve, with
central hinge pins that extend through the valve body and provide visual confirmation of
check valve installation in a vertical or horizontal orientation.
On July 14, 2017, the 12SW536 failed its reverse flow quarterly IST. In response, PSEG
immediately entered the action statement associated with TS LCO 3.6.1.1, Containment
Integrity, which required restoring containment integrity within one hour, or shutdown
within the next six hours. PSEG operators closed manual valves and isolated the 12 SW
accumulator tank from the 14 and 15 CFCUs, and exited TS LCO 3.6.1.1 in 52 minutes.
17
However, closing the manual isolation valves rendered 14 and 15 CFCUs inoperable,
and required entry into TS LCO 3.6.2.3, Containment Cooling System, action a, which
required restoration within seven days or shutdown within the next six hours.
With SW isolated to 14 and 15 CFCUs, PSEG subsequently drained the 12 SW
accumulator tank, and opened the 12SW536 check valve for inspection. PSEG
identified that the check valve was installed with the hinge pins in a horizontal
orientation, and further noted that silt accumulation was impacting the ability of the
bottom plate to close. PSEG performed extent of condition inspections and determined
that the other three SW accumulator injection check valves on Unit 1 and Unit 2 were all
installed with the hinge pins in the vertical orientation. PSEG also reviewed the vendor
manual, and confirmed that the preferred orientation for a horizontal piping system was
with the hinge pins in a vertical orientation. Additionally, PSEG noted that on July 10,
2017, an annual preventive maintenance (PM) activity was conducted to determine the
level of silt accumulation in the piping upstream of the 12SW536. The ultrasonic testing
(UT) identified four inches of silt build-up in the 10-inch diameter pipe. No further action
was taken because the acceptance criteria was five inches, based on station calculation
S-C-SW-MEE-1910, Salem CFCU Accumulator Injection Piping - Allowable Levels of
Silt Accumulation during Plant Operation, Revision 1. PSEG further noted that the
calculation performed a force-moment balance on the check valve plates using a vertical
orientation for the hinge pins. PSEG captured the issue in CAP as NOTF 20771353,
and performed ERE 70195309. The ERE concluded that the valve was installed in the
incorrect orientation in 2008, during implementation of design change package (DCP)
that moved the physical location of the SW accumulator injection check valves, but did
not incorporate specific hinge pin orientation guidance into drawings or work instructions.
PSEG created C/As to revise work instructions to incorporate specific instructions
regarding hinge pin orientation during installation of the SW accumulator check valves.
The inspectors reviewed the PM history of the 12SW536, to identify if the valve had
been physically worked since 2008. The inspectors reviewed a previously completed
PM activity to open and inspect the valve, under WO 50092024, which was performed
concurrently with the DCP activity. The inspectors noted the PM was performed in
accordance with PSEG procedure SC.MD-PM.ZZ-0123, Disassembly, Inspection and
Reassembly of Dual Plate Check Valves, Revision 13. During review of the completed
procedure, the inspectors identified step 5.4.16, which required a supervisor hold point
to install the check valve with the hinge pins vertical in a horizontal piping system, or
horizontal in a vertical piping system, was marked N/A on October 22, 2008. The
inspectors determined that PSEG did not follow step 5.4.16 of maintenance procedure
SC.MD-PM.ZZ-0123, which resulted in the valve being installed with the hinge pins in
the wrong orientation, and subsequently resulted in the failed reverse flow IST on
July 14, 2017. PSEG captured the inspector-identified aspects of this issue in NOTFs in
20775965 and 20776321.
Analysis. The inspectors determined there was a performance deficiency that was
within PSEGs ability to foresee and correct because maintenance procedure
SC.MD-PM.ZZ-0123, Disassembly, Inspection and Reassembly of Dual Plate Check
Valves, Revision 13, step 5.4.16, instructed technicians to install the check valve in the
correct orientation, but PSEG marked the step N/A and installed the valve in the wrong
orientation. This issue was more than minor since it was associated with the
configuration control attribute of the Barrier Integrity Cornerstone and adversely
impacted its objective to provide reasonable assurance that physical design barriers
18
(containment) protect the public from radionuclide releases cause by accidents or
events. Specifically, installing the 12SW536 check valve in the wrong orientation
impacted the ability of the valve to close and support containment integrity by preventing
voids and water hammer during certain design basis accidents. Using IMC 0609,
Attachment 4 and Appendix A, Exhibit 3, the inspectors determined that this finding was
of very low safety significance, or Green, because the finding did not result in an actual
open pathway in the physical integrity of reactor containment.
The inspectors determined there was no cross-cutting aspect associated with this finding
since it was not representative of current PSEG performance. Specifically, the
12SW536 valve was installed in the wrong orientation on October 22, 2008. In
accordance with IMC 0612, the causal factors associated with this finding occurred
outside the nominal three-year period of consideration and were not considered
representative of present performance.
Enforcement. TS 6.8.1, Procedures and Programs, states, in part, that written
procedures shall be established, implemented, and maintained covering the applicable
procedures recommended in Appendix A of RG 1.33, Revision 2, February 1978.
RG 1.33, Revision 2, February 1978, Section 9, Procedures for Performing
Maintenance, states, in part, that maintenance that can affect the performance of
safety-related equipment should be properly preplanned and performed in accordance
with written procedures. Contrary to the above, on October 22, 2008, PSEG procedure
SC.MD-PM.ZZ-0123, Disassembly, Inspection and Reassembly of Dual Plate Check
Valves, Revision 13, was not performed in accordance with step 5.4.16, which required
a supervisor hold point to install the 12SW536 check valve with the hinge pins vertical in
a horizontal piping system. Consequently, the check valve was installed with the hinge
pins horizontal, which prevented the valve from closing in the presence of silt, and
therefore impacted the ability of the valve to support containment integrity during certain
design basis accidents. PSEG entered this issue in the CAP as NOTFs 20771353 and
20776321, and performed ERE 70195309. The C/As consisted of removing the check
valve from the system, clearing the silt build-up, and reinstalling the check valve in the
correct orientation on July 15, 2017. Because this violation was of very low safety
significance (Green), and was entered into PSEGs CAP, this issue is being treated as
an NCV consistent with Section 2.3.2.a of the Enforcement Policy.
(NCV 05000272/2017003-03, Failure to Follow Maintenance Procedure to Assure
Proper Installation of Service Water Check Valve)
2. RADIATION SAFETY
Cornerstones: Occupational and Public Radiation Safety
2RS2 Occupational As Low As Reasonably Achievable Planning and Controls
(71124.02 - 1 sample)
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,
Regulatory Guides 8.8 and 8.10, TSs, and procedures required by TSs as criteria for
determining compliance.
19
Radiological Work Planning (1 sample)
The inspectors selected the following radiological work activities based on exposure
significance for review:
- Radiation work permit (RWP) 1, Task 92, radiation protection support refuel
- RWP 24, Task 2213002, baffle bolt repairs
- RWP 22, Task 222, containment scaffold
- RWP 26, Task 15, fuel moves
For each of these activities, the inspectors reviewed: ALARA work activity evaluations,
exposure estimates, exposure reduction requirements, results achieved (dose rate
reductions, actual dose), person-hour estimates and results achieved and post-job
reviews that were conducted to identify lessons learned.
b. Findings
No findings were identified.
2RS6 Radioactive Gaseous and Liquid Effluent Treatment (71124.06 - 6 samples)
a. Inspection Scope
The inspectors reviewed the treatment, monitoring, and control of radioactive gaseous
and liquid effluents. The inspectors used the requirements in 10 CFR Part 20; 10 CFR
Part 50, Appendix I; TS; Offsite Dose Calculation Manual (ODCM); applicable industry
standards; and procedures required by TSs as criteria for determining compliance.
Inspection Planning
The inspectors conducted in-office reviews of the Salem 2015 and 2016 annual
radioactive effluent and environmental reports, radioactive effluent program documents,
UFSAR, ODCM, and applicable event reports.
Walkdowns and Observations (1 sample)
The inspectors walked down the gaseous and liquid radioactive effluent monitoring and
filtered ventilation systems to assess the material condition and verify proper alignment
according to plant design. The inspectors also observed potential unmonitored release
points and reviewed radiation monitoring system surveillance records and the routine
processing and discharge of gaseous and liquid radioactive wastes.
Calibration and Testing Program (1 sample)
The inspectors reviewed gaseous and liquid effluent monitor instrument calibration,
functional test results, and alarm setpoints based on National Institute of Standards and
Technology calibration traceability and ODCM specifications.
20
Sampling and Analyses (1 sample)
The inspectors reviewed radioactive effluent sampling activities, representative sampling
requirements, compensatory measures taken during effluent discharges with inoperable
effluent radiation monitoring instrumentation, the use of compensatory radioactive
effluent sampling, and the results of the inter-laboratory and intra-laboratory comparison
program, including scaling of hard-to-detect isotopes.
Instrumentation and Equipment (1 sample)
The inspectors reviewed the methodology used to determine the radioactive effluent
stack and vent flow rates to verify that the flow rates were consistent with TS/ODCM and
UFSAR values. The inspectors reviewed radioactive effluent discharge system
surveillance test results based on TS acceptance criteria. The inspectors verified that
high-range effluent monitors used in emergency operating procedures are calibrated and
operable and have post-accident effluent sampling capability.
Dose Calculations (1 sample)
The inspectors reviewed changes in reported dose values from the previous annual
radioactive effluent release reports, several liquid and gaseous radioactive waste
discharge permits, the scaling method for hard-to-detect radionuclides, ODCM changes,
land use census changes, public dose calculations (monthly, quarterly, annual), and
records of abnormal gaseous or liquid radioactive releases.
Problem Identification and Resolution (1 sample)
The inspectors evaluated whether problems associated with the radioactive effluent
monitoring and control program were identified at an appropriate threshold and properly
addressed in Salems CAP.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
Mitigating Systems Performance Index (4 samples)
a. Inspection Scope
The inspectors reviewed PSEGs submittal of the Mitigating Systems Performance Index
for the following systems for the period of July 1, 2016 through June 30, 2017.
- Common, Heat removal system (MS08)
- Common, Residual heat removal system (MS09)
To determine the accuracy of the performance indicator (PI) data reported during those
periods, the inspectors used definitions and guidance contained in Nuclear Energy
21
Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator
Guideline, Revision 7. The inspectors also reviewed PSEGs operator narrative logs,
NOTFs, mitigating systems performance index derivation reports, event reports, and
NRC integrated inspection reports to validate the accuracy of the submittals.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution (71152)
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 C/As, 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 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
b. Findings
No findings were identified.
4OA6 Meetings, Including Exit
On October 10, 2017, the inspectors presented the inspection results to Mr. Charles
McFeaters, Salem Vice President, and other members of the PSEG staff. The
inspectors verified that no proprietary information was retained by the inspectors or
documented in this report. PSEG management indicated they may contest the NCV in
Report Section 1R15.2.
ATTACHMENT: SUPPLEMENTARY INFORMATION
A-1
SUPPLEMENTARY INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
C. McFeaters, Salem Vice President
P. Martino, Plant Manager, Salem
T. Carucci, 12-Hr Maintenance Supervisor
R. DeNight, Engineering Director
J. Fleming, Director of Site Regulatory Compliance
J. Guinta, Systems Engineer
R. Heathwaite, REMP/REC Program Manager
D. Lynn, Mechanical Maintenance Supervisor
M. Maroles, Senior Reactor Operator
G. Morrison, Design Engineering
B. Muffley, Shift Operations Manager
T. Mulholland, Plant Engineering Senior Manager
T. Turek, System Engineer
J. Tutterow, System Engineer
J. Scull, Maintenance Director
J. Wearne, Compliance Manager
A. Zhang, Lead Engineer
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Open and Closed
05000272/2017003-01 NCV Expiration of Periodic Inservice Testing of
14 Service Water Pump (Section 1R15.1)05000272/2017003-02 NCV Violation of Containment Integrity Technical
Specification (Section 1R15.2)05000272/2017003-03 NCV Failure to Follow Maintenance Procedure
to Assure Proper Installation of Service
Water Check Valve (Section 1R22)
LIST OF DOCUMENTS REVIEWED
- Indicates NRC-identified
Section 1R01: Adverse Weather Protection
Procedures
OP-AA-108-111-1001, Severe Weather and Natural Disaster Guidelines, Revision 14
SC.OP-AB.ZZ-0001, Adverse Environmental Conditions, Revision 19
SC.OP-PT.ZZ-0002, Station Preparations for Seasonal Conditions, Revision 14
WC-AA-107, Seasonal Readiness, Revision 14
SC.MD-PM.ZZ-0036, Watertight Door Inspection and Repair, Revision 7
Attachment
A-2
Notifications
20704888 20769517* 20771357*
20704978 20769518*
20708365 20770715*
Work Orders
30301872
30302998
60126201
Other Documents
IPEEE, VTDs 320758, 323042, and 320058
UFSAR, Sections 2.4 and 3.4
Focused Evaluation of External Floods for SGS Units 1 and 2, PSEG letter dated 6/30/17
Section 1R04: Equipment Alignment
Notifications
20773687*
20775216*
20772119
Drawings
223684, 2B Diesel Generator Engine Generator Control, Revision 36
223685, 1B & 2B Diesel Generators Alarms, Revision 16
223686, 1B & 2B Diesel Generator Unit Trip & Breaker Failure Protection, Revision 24
226632, Diesel Generators Protection and Control, Revision 11
Work Orders
30254228
Section 1R05: Fire Protection
Procedures
FP-SA-1141, Pre-Fire Plan Salem Unit 1 Turbine Building, Revision 0
FP-SA-2141, Pre-Fire Plan Salem Unit 2 Turbine Building, Revision 0
FP-SA-2651, Pre-Fire Plan Salem Unit 2 Service Water Intake Structure, Revision 0
SC.FP-SV.ZZ-0058, Inspection of Class 1 Fire Doors and Safety Related Areas for Transient
Combustibles, Revision 22
Notifications
20770507* 20774498* 20775183*
20770520* 20774605* 20772154
20772737* 20776151*
A-3
Section 1R11: Licensed Operator Requalification Program
Procedures
2-EOP-LOCA-3, Transfer to Cold Leg Recirculation, Revision 31
2-EOP-LOCA-1, Loss of Reactor Coolant, Revision 30
2-EOP-LOSC-2, Multiple Steam Generator Depressurization, Revision 31
2-EOP-TRIP-1, Reactor Trip or Safety Injection, Revision 32
Notifications
20774803*
20774804*
20774911*
Other Documents
Scenario Guide ESG-A301
Scenario Guide ESG-A303
Section 1R12: Maintenance Effectiveness
Notifications
20606407 20774903* 20772312
20607099 20777124 20772314
20771900* 20774649 20771840
20771917* 20774650 20770295
20774408* 20772312 20766832
Work Orders
30151474 60104541 70153482
30208976 60135986
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
Testing/Inspection, Revision 17
OP-AA-108-116, Protected Equipment Program, Revision 12
S2.OP-SO.DG-0002, 2B Diesel Generator Operation, OTSC 38A S2.OP-ST.DG-0002, 2B
Diesel Generator Surveillance Test, OTSC 51A
SC.MD-FT.DG-0001, Emergency Diesel Generator Field Flashing Relay K1C
WC-AA-105, Work Activity Risk Management, Revision 6
Notifications
20606407 20771143 20774092*
20607099 20771219 20774193*
20635535 20771386* 20774593*
20689438 20771387* 20775330*
20769376* 20771396*
Work Orders
30151474 60120347 70153482
30208976 60125811 70162247
60104541 60135986
A-4
Other Documents
Operations Narrative Logs for July 25, 2017
PSE-99233, Failure Analysis of K1C Field Flash Relay, dated 28 February 2014
Unit 1 risk assessment for work weeks 730 and 732
Section 1R15: Operability Determinations and Functionality Assessments
Procedures
EP-AA-121-1003, Equipment Important to Emergency Response - Work Prioritization,
Revision 3
LS-AA-104-1000, 50.59 Resource Manual, Revision 8
MA-AA-716-210, Preventive Maintenance (PM) Program, Revision 10
MA-AA-716-210-1005, Predefine Change Processing, Revision 7
OP-AA-108-103, Locked Equipment Program, Revision 4
OP-AA-108-103-1001, Locked Equipment Program, Revision 1
OP-SA-108-115-1001, Operability Assessment and Equipment Control Program, Revision 10
S1.CH-AB.CBV-1076, Unit 1 Containment Atmosphere Sampling Under Accident Conditions,
Revision 0
S1.CH-AB.CBV-1243, Unit 1 Containment Atmosphere Sampling, Revision 1
S1.OP-ST.CAN-0001, Primary Containment Valves Monthly, Revisions 12 and 13
S1.OP-ST.CAN-0002, Inside Containment Valve Verification Modes 1-4, Revision 3
S2.OP-LR.MP-0001, Type B Mechanical Penetration Leak Rate Testing, Revision 1
SC.OP-AB.ZZ-0004, Earthquake, Revision 2
Notifications
20759443 20772465 20715581*
20771139 20772467 20672535
20774499* 20771321 20712428*
20775815* 20772906 20710999
20776222* 20770576 20714946
20776155* 20771219 20706526
20776775* 20771143 20706527
20777736 20751413* 20706785
20772751 20751688* 20695345
20772751 20777663* 20705558
20768780 20712428 20672533
20771376 20715581 20663402
20774437 20714946 20663402
Drawings
201193, Unit 1 and 2 Reactor Containment Equipment Hatch and Personnel Locks
205238, Unit 1 Reactor Containment - Ventilation, Sheet 1, Revision 38
208070, Unit 1 - Containment Area Shielding and Heavy Equipment Handling Plan, Sheet 1,
Revision 10
201193, Units 1 and 2 - Reactor Containment Equipment Hatch and Personnel Locks,
Revision 11
219508, Yard, Salem Roadways and Finished Grading, Sheet 1, Revision 54
223684, 2B Diesel Generator Engine - Generator Control, Sheet 2, Revision 36
223685, 1B and 2B Diesel Generators, Alarms, Revision 16
223686, 1B and 2B Diesel Generators, Unit Trip and Breaker Failure Protection, Revision 24
226632, Units 1 and 2 - Diesel Generators Protection and Control, Revision 11
A-5
252312, Salem and Hope Creek Yard Master Site Plan - Temporary Facilities, Sheet 1,
Revision 9
601232, 1B 460V Vital Bus One-Line, Revision 18
601669, Units 1 and 2 General Building Room Locations, Revision 4
Work Orders
40025088 70178637 70192466
60134574 70183531 80112838
60135562 70191433 80119985
Other Documents
1-EOP-TRIP-1, Reactor Trip or Safety Injection, Sheet 2 of 6, Revision 31
50.59 Screening S2014-172, DCR 80112838, Revision 0
6SO-1471, Analysis and Design of Equipment Hatch for Salem Units 1 and 2, Revision 1
CC-AA-201, Plant Barrier Control Program, Revision 5
Equipment Reliability Evaluation 70195311, 2B EDG K1C Relay Did Not Reset After Run
NEI 96-07, Guidelines for 10 CFR 50.59 Implementation, Revision 1
NUMARC 93-01, NEI Industry Guidelines for Monitoring the Effectiveness of Maintenance at
Nuclear Power Plants, Revision 4A
NRC Generic Letter 91-08, Removal of Component Lists from Technical Specifications
NRC Issuance of License Amendments Re: Alternate Source Term, dated February 17, 2006,
NRC Issuance of License Amendments Re: Containment Isolation Valves Technical
Specifications, dated October 2, 2000, ML003746674
NRC Safety Evaluation Re: Amendment 189 to Unit 1 and 172 to Unit 2, Removal of
Containment Isolation Valve Table from Technical Specifications, dated January 30,
1997
NRC Regulatory Issue Summary 2001-09: Control of Hazard Barriers
NRC Regulatory Issue Summary 2008-14: Use of TORMIS Computer Code for Assessment of
NRC Regulatory Issue Summary 2013-05: NRC Position on the Relationship between General
Design Criteria and Technical Specification Operability
NRC Regulatory Issue Summary 2015-06: Tornado Missile Protection
Enforcement Guidance Memorandum 15-002, Enforcement Discretion for Tornado-Generated
Missile Protection Non-compliance, Revision 1
NUREG-1431, Westinghouse Standard Technical Specifications, Revision 4
Plant Barrier Impairment 14-076 (30254980), Remove Outer Equipment Hatch, approved
10/19/14
Plant Barrier Impairment 15-090 (30275227), Remove Outer Equipment Hatch, approved
10/17/15
Plant Barrier Impairment 17-044 (30291359-0025), Remove Outer Equipment Hatch, approved
04/12/17
PSEG Request for License Amendment - Containment System - Salem, dated March 2, 2000
S1-CRM-006, S1R23: Removal of Unit 1 Containment Concrete Missile Shields and Outer
Hatch While Operating in Modes 1, 2, 3 and 4, Revision 0
S-C-CAN-SDC-2330, Containment Hatch Tornado Missile Evaluation, Revision 0
S-C-ZZ-MDC-1945, Post-LOCA Doses - Alternate Source Term (AST), Revision 4
S-C-ZZ-SDC-1203, Moderate Energy Break Analysis (Reconstitution), Revision 3
Standard Review Plan 3.5.3, Barrier Design Procedures, Revision 1
Technical Evaluation 30153966-005-0020, CFCU Draining and SW Room HELB/MELB Door
Functionality
A-6
Temporary Standing Order 2017-008, Guidance for EAL Classification for Operating Basis
Technical Requirements Manual Table 3.6-1, Containment Isolation - Major Piping
Penetrations, Revision 3
Unit 2 Control Room Supervisor Turnover Checklist, dated December 27, 2016
VTD 301051
VTD 301053
WCAP-15791-NP-A, Risk-Informed Evaluation of Extensions to Containment Isolation Valve
Completion Times, Revision 2
Section 1R18: Plant Modifications
Notifications
20773802* 20774065* 20774372* 20775829*
Work Orders
80120809
Other Documents
50.59 Screening, S2017-159, Revision 0
TCCP 2ST17-012, Salem Service Water Pump Discharge Head Stiffener Plate Installation,
Revision 0
UFSAR Section 9.2.1.2
Section 1R19: Post-Maintenance Testing
Procedures
S1.OP-ST.SW-0001, Inservice Testing - 11 Service Water Pump, Revision 37
S2.OP-ST.SW-0008, Inservice Testing Service Water Valves (Aux Bldg) Modes 1-4,
Revision 17 (Post-Maintenance test conducted on July 22, 2017)
SC.IC-FT.RCP-0009, 2TE-431A-B #23 Rx Coolant Loop Delta T-Tavg Protection Channel III,
Revision 61
MA-AA-734-463, Maintenance of Fan Drive Belt Systems, Revision 0
Notifications
20579624 20775023 20702022
20771600 20775189 20776064*
20772204 20775073
20772206 20774977
Drawings
205242, Sheet 1, Service Water Nuclear Area, Revision 100
601837, Reactor Protection & Process Control Systems, Revision 5
Work Orders
60119760 50184149 30238558
60135930 50195247 60136298
60135965 60136339
A-7
Other Documents
IST program basis for valve S2SW-22SW122
Operations Narrative Logs for July 23, 2017
Calculations
S-C-SW-MDC-2146, Revision 2
Section 1R22: Surveillance Testing
Procedures
S1.OP-ST.CS-0001, Inservice Testing - 11 Containment Spray Pump, Revision 20
S1.RA-ST.CC-0002, Inservice Testing 12 Component Cooling Pump Acceptance Criteria,
Revision 15
S1.RA-ST.CS-0001, Inservice Testing 11 Containment Spray Pump Acceptance Criteria,
Revision 8
SC.MD-PM.SW-00003, SW Auto Strainer Adjustment, Inspection, Repair, and Replacement,
Revision 62
Notifications
20772390* 20774819* 20772380
20772390* 20775965* 20772382
20772983* 20777726* 20771279
20773095 20777727* 20771282
20774761* 20777841* 20771489
20774872* 20771918 20771353
20774884* 20770854
20774908* 20775038
Drawings
205235, Containment Spray, Revision 48
205242, Unit 1 Service Water Nuclear, Sheet 7, Revision 5
205242, Unit 1 Service Water Nuclear, Sheet 5, Revision 85
205242, Unit 1 Service Water Nuclear, Sheet 6, Revision 94
605392, Unit 1 Penetration Area Service Water Piping Plan, Elevations 78 and 100, Revision 0
Work Orders
30311964 50193850 50196350
50092024 50194526 50197783
50184454 50195172 60069765
50184463 50196334 70156170
50191535 50196334 80092251
Other Documents
Equipment Reliability Evaluation 70195309, 12SW536 Failed Reverse Flow Test
S1.OP-ST.CC-0002, Inservice Testing - 12 Component Cooling Pump, Revision 26,
completed 08/08/17
S-C-SW-MEE-1162, Service Water System Failure Modes and Effects Analysis, Revision 5
VTD 172479
VTD 304931
VTD 306208
A-8
Section 2RS2: Occupational ALARA Planning and Controls
Miscellaneous
Salem Unit 2 22nd ALARA Outage Report
Section 2RS6: Radioactive Gaseous and Liquid Effluent Treatment
Procedures
S1.IC-CC.RM-0016, 1R12A Containment Atmosphere Noble Gas Process Radiation Monitor,
Revision 19
S1.IC-CC.RM-0028, 1R18 Liquid Waste Disposal Process Radiation Channel, Revision 15
S1.IC-CC.RM-0029, 1R19A steam Generator 11 Blowdown Process Radiation Monitor,
Revision 20
S1.IC-CC.RM-0030, 1R19B Steam Generator 12 Blowdown Process Radiation Monitor,
Revision 24
S1.IC-CC.RM-0031, 1R19C Steam Generator 13 Blowdown Process Radiation Monitor,
Revision 21
S1.IC-CC.RM-0064, 1R41A Low Range/1R41D Composite Plant Vent Noble Gas Process
Radiation Monitor, Revision 21
S1.IC-CC.RM-0065, 1R41B Plant Vent Intermediate Range Noble Gas Process Radiation
Monitor, Revision 21
S1.IC-CC.RM-0066, 1R41C Plant Vent High Range Noble Gas Process Radiation Monitor,
Revision 18
S1.IC-CC.RM-0088, 1R41 Plant Vent Noble Gas Sample and Process Flow Calibration,
Revision 16
S1.IC-CC.RM-0097, 1R13A #11, #12 and #13 Containment Fan Coolers Service Water Line
Discharge Process Radiation Monitors, Revision 6
S1.IC-FT.RM-0016, 1R12A Containment Atmosphere Noble Gas Process Radiation Monitor,
Revision 25
S1.IC-FT.RM-0067, 1R41D Plant Vent Noble Gas Release Rate Process Radiation Monitor,
Revision 28
S1.IC-FT.RM-0091, 1R13B #13, #14, and #15 Containment Fan Coolers - Service Water Line
Discharge Process Radiation Monitor, Revision 6
S1.IC-FT.RM-0129, 1R19A-D Steam Generator Blowdown Process Radiation Monitors,
Revision 11
S1.IC-LC.GBD-0001, Steam Generator Blowdown Flow Instrument Loop Calibration,
Revision 16
S1.OP-SO.WL-0001, Release of Radioactive Liquid Waste from 11 CVCS Monitor Tank,
Revision 24
S1.OP-ST.RM-0001, Radiation Monitors - Check Sources, Revision 31
S1.RA-PT.ABV-0002, Auxiliary Building Exhaust Ventilation System Periodic Test, Revision 0
S1.RA-ST-FHV-0001, Fuel Handling Building Ventilation System Surveillance Test, Revision 6
S2.IC-CC.RM-0016, 2R12A Containment Atmosphere Noble Gas Process Radiation
Monitor - Channel 3, Revision 20
S2.IC-CC.RM-0060, R37 Chemical Waste Basin Process Radiation Monitor, Revision 13
S2.IC-CC.RM-0064, 2R41A Low Range/2R41D Composite Plant Vent Noble Gas Process
Radiation Monitor, Revision 28
S2.IC-CC.RM-0065, 2R41B Plant Vent Intermediate Range Noble Gas Process Radiation
Monitor, Revision 22
S2.IC-CC.RM-0088, 2R41 Plant Vent Noble Gas Sample and Process Flow Calibration,
Revision 17
A-9
S2.IC-FT.RM-0016, 2R12A Containment Noble Gas Process Radiation Monitor Channel 3,
Revision 24
S2.IC-FT.RM-0067, 2R41D Plant Vent Noble Gas Release Rate Process Radiation Monitor,
Revision 35
S2.IC-FT.RM-0091, 2R13B #23, #24, and #25 Containment Fan Coolers - Service Water Line
Discharge Process Radiation Monitor, Revision 12
S2.IC-FT.RM-0129, 2R19A-D Steam Generator Blowdown Process Radiation Monitors,
Revision 10
S2.IC-LC.GBD-0001, Steam Generator Blowdown Flow Instrument Loop Calibration,
Revision 18
S2.RA-PT-ABV-0001, Auxiliary Building Exhaust Ventilation System Periodic Test, Revision 1
S2.RA-PT.ABV-0002, Auxiliary Building Exhaust Ventilation System Airflow Rate Verification with
Different ABV Fan Lineups, Revision 1
S2.RA-ST.FHV-0001, In-service Inspection Fuel Handling Building Exhaust Ventilation System
Surveillance Test, Revision 8
CY-AA-130-205, Radiochemistry Quality Control, Revision 0
SC.RA-IS.IRU-0001, Iodine Removal Ventilation System Surveillance Test, Revision 2
SC.MD-PM-ZZ-0206, Charcoal Filter Maintenance, Revision 1
Notifications
20762150
20768807
Quality Assurance
Check In Self-Assessment - 2017 NRC Radiological Effluent Control Inspection, July 24, 2017
Chemistry Count Room Control Charts for: Germanium Detectors: Liquid Scintillation Counters
Chemistry, Radwaste, Effluent and Environmental Monitoring Audit report, Audit
NOSA-SLM-16-04, May 2016
Eckert & Ziegler Analytics Results of Radiochemistry Cross Check Program, PSEG Salem for
1st Quarter 2015 thru 1st Quarter 2017
Release Permits
Gaseous Radioactive Waste Release Permits: 63360.173.039.G; 64385.273.067.G;
64002.251.674.G 64843.172.041.G; 63161.272.052.G; 63222.151.595.G;
64014.172.033.G; 64847.272.060.G; 65137.263.035.G; 64765.262.616.G
Liquid Radioactive Waste Release Permits: 53329.201.101.L; 53343.102.352.L;
53398.143.599.L; 53711.101.406.L; 53750.201.142.L; 53780.142.645.L;
53879.101.426.L; 53902.201.158.L; 53930.143.666.L
Miscellaneous
NUCON International, Inc. Radioiodine Test Reports Salem Units 1 & 2
Offsite Dose Calculation Manual for PSEG Nuclear LLC Salem Generating Station, Revision 27
PSEG Nuclear LLC 2015 Annual Radioactive Effluent Release Report
PSEG Nuclear LLC 2016 Annual Radioactive Effluent Release Report
Section 4OA1: Performance Indicator Verification
Notifications
20766760
20770242
20774839*
A-10
Other Documents
Unavailability and Unreliability Derivation Reports for Units 1 and 2 for Cooling Water and Heat
Removal Systems for June 2016 and June 2017
Section 4OA2: Problem Identification and Resolution
Notifications
20769760* 20774035* 20769257
20769761* 20774382* 20774424
20769941* 20775033* 20774308
20770828* 20775166* 20774182
20771562* 20775651* 20774473
20771639* 20775674* 20774175
20771892* 20775766* 20774541
20771894* 20775772* 20774588
20772079* 20775688* 20774299
20772814* 20775803* 20774300
20773190* 20775573*
20773265* 20777654
Drawings
Adverse Condition Monitoring and Contingency Plan 17-006, Unit 2 Stator Cooling Water Flow,
601703, Unit 2 Stator Winding Cooling Water System, Revision 1
A-11
LIST OF ACRONYMS
10 CFR Title 10 of the Code of Federal Regulations
ACE apparent cause evaluation
ADAMS Agencywide Documents Access and Management System
ALARA as low as is reasonably achievable
APD air particulate detector
ASME American Society of Mechanical Engineers
C/A corrective action
CAP Corrective Action Program
CCW component cooling water
CFCU containment fan cooling unit
CFR Code of Federal Regulations
CIV containment isolation valve
DCP design change package
D/P differential pressure
EDG emergency diesel generator
EOP emergency operating procedure
ERE equipment reliability evaluation
HX heat exchanger
IMC inspection manual chapter
IR inspection report
IST inservice test
LCO limiting condition for operation
LERF large early release frequency
LOCA loss of coolant accident
LOOP loss of offsite power
MELB Moderate Energy Line Break
MR maintenance rule
NCV non-cited violation
NEI Nuclear Energy Institute
NOTF notification
NRC Nuclear Regulatory Commission
NRR Nuclear Reactor Regulation
ODCM off-site dose calculation manual
OM operations and maintenance
OOS out of service
OpEval Operability Evaluation
PI performance indicator
PM preventive maintenance
PSEG Public Service Enterprise Group Nuclear LLC
ROP Reactor Oversight Process
RTP rated thermal power
RWP radiation work permit
SDP significance determination process
SLIV severity level IV
SR surveillance requirement
SSC structure, system, and component
SWIS service water intake structure
A-12
TE technical evaluation
TRM technical requirements manual
TS technical specification(s)
UFSAR Updated Final Safety Analysis Report
UT ultrasonic testing
WO work order