ML14209A132
| ML14209A132 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 07/28/2014 |
| From: | Glenn Dentel Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| DENTEL, GT | |
| References | |
| IR-14-003 | |
| Download: ML14209A132 (50) | |
See also: IR 05000354/2014003
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION I
2100 RENAISSANCE BLVD., SUITE 100
KING OF PRUSSIA, PA 19406-2713
July 28, 2014
Mr. Thomas P. Joyce
President and Chief Nuclear Officer
P.O. Box 236
Hancocks Bridge, NJ 08038
SUBJECT: HOPE CREEK GENERATING STATION UNIT 1 - NRC INTEGRATED
INSPECTION REPORT 05000354/2014003
Dear Mr. Joyce:
On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Hope Creek Generating Station (HCGS). The enclosed inspection report documents the
inspection results, which were discussed on July 10, 2014 with Mr. P. Davison, Site Vice
President of Hope Creek, and other members of your staff.
The inspection 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.
This report documents one NRC-identified and four self-revealing findings of very low safety
significance (Green). Three of these findings were determined to involve a violation of NRC
requirements. Additionally, a licensee-identified violation, which was determined to be of very
low safety significance, is listed in this report. However, because of the very low safety
significance, and because they are entered into your corrective action program (CAP), the NRC
is treating the findings as non-cited violations (NCVs) consistent with Section 2.3.2.a of the
NRC Enforcement Policy. If you contest any NCVs 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 HCGS. 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
HCGS.
T. Joyce 2
In accordance with Title 10 of the Code of Federal Regulations (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 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/
Glenn T. Dentel, Chief
Reactor Projects Branch 3
Division of Reactor Projects
Docket Nos.: 50-354
License Nos.: NPF-57
Enclosure: Inspection Report 05000354/2014003
w/Attachment: Supplementary Information
cc w/encl: Distribution via ListServ
Non-Sensitive Publicly Available
SUNSI Review
Sensitive Non-Publicly Available
OFFICE RI/DRP RI/DRP RI/DRP
NAME JHawkins/ RSB for RBarkley/ RSB GDentel/ GTD
DATE 07/22 /14 07 /22/14 07 / 28 /14
1
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos.: 50-354
License Nos.: NPF-57
Report No.: 05000354/2014003
Licensee: Public Service Enterprise Group (PSEG) Nuclear LLC
Facility: Hope Creek Generating Station (HCGS)
Location: P.O. Box 236
Hancocks Bridge, NJ 08038
Dates: April 1, 2014 through June 30, 2014
Inspectors: J. Hawkins, Senior Resident Inspector
S. Ibarrola, Resident Inspector
H. Gray, Senior Reactor Inspector
Approved By: Glenn T. Dentel, Chief
Reactor Projects Branch 3
Division of Reactor Projects
Enclosure
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TABLE OF CONTENTS
SUMMARY ................................................................................................................................ 3
REPORT DETAILS .................................................................................................................... 7
1. REACTOR SAFETY ........................................................................................................... 7
1R01 Adverse Weather Protection .................................................................................... 7
1R04 Equipment Alignment ............................................................................................... 8
1R05 Fire Protection .......................................................................................................... 9
1R06 Flood Protection Measures .....................................................................................10
1R11 Licensed Operator Requalification Program ...........................................................13
1R12 Maintenance Effectiveness .....................................................................................14
1R13 Maintenance Risk Assessments and Emergent Work Control ................................16
1R15 Operability Determinations and Functionality Assessments ....................................19
1R18 Plant Modifications .................................................................................................20
1R19 Post-Maintenance Testing ......................................................................................20
1R22 Surveillance Testing ...............................................................................................21
1EP6 Drill Evaluation .......................................................................................................22
4. OTHER ACTIVITIES ..........................................................................................................22
4OA1 Performance Indicator (PI) Verification ....................................................................22
4OA2 Problem Identification and Resolution ....................................................................23
4OA3 Follow-Up of Events and Notices of Enforcement Discretion ..................................24
4OA5 Other Activities ........................................................................................................30
4OA6 Meetings, Including Exit ...........................................................................................31
4OA7 Licensee-Identified Violations ..................................................................................31
ATTACHMENT: SUPPLEMENTARY INFORMATION...............................................................31
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-2
LIST OF ACRONYMS ........................................................................................................... A-15
Enclosure
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SUMMARY
IR 05000354/2014003; 4/01/2014 - 6/30/2014; Hope Creek Generating Station; Flood
Protection Measures, Maintenance Effectiveness, Maintenance Risk Assessments and
Emergent Work Control, Follow-up of Events and Notices of Enforcement Discretion.
This report covered a three-month period of inspection by the resident inspectors and
announced inspections performed by regional inspectors. Five findings of very low safety
significance (Green) were identified. Three of the findings were determined to be violations of
NRC requirements. 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 June 2, 2011. Cross-cutting
aspects are determined using IMC 0310, Components Within Cross-Cutting Areas, dated
December 19, 2013. All violations of NRC requirements are dispositioned in accordance with
the NRCs Enforcement Policy, dated July 9, 2013. The NRCs program for overseeing the safe
operation of commercial nuclear power reactors is described in NUREG-1649, Reactor
Oversight Process, Revision 5.
Cornerstone: Initiating Events
Green. A self-revealing finding of very low safety significance (Green) was identified for
PSEGs failure to evaluate an identified deficiency in accordance with PSEG procedure
LS-AA-125, Corrective Action Program. Specifically, PSEG failed to take self-
recommended actions in notification (NOTF) 20447050 to evaluate the B moisture
separator (MS) dump valve performance after failing to operate as designed during B MS
drain valve troubleshooting on January 11, 2010. As a result, PSEG did not identify and
correct a potential design flaw associated with thermal binding of the MS dump valves,
which was determined to be the cause of the A MS dump valve failing to stroke open on
December 1, 2013, leading to a reactor scram from 100 percent power. PSEGs corrective
actions include a design change to the MS emergency level control system that eliminates
dump valve cycling on high MS level.
The performance deficiency was determined to be more than minor because it was
associated with the equipment performance attribute of the Initiating Events cornerstone,
and adversely affected the cornerstone objective to limit the likelihood of events that upset
plant stability and challenge critical safety functions during shutdown as well as power
operations. The inspectors determined that this finding was of very low safety significance
(Green) using Exhibit 1 of NRC IMC 0609, Appendix A, The Significance Determination
Process (SDP) for Findings At-Power, dated June 19, 2012, because the finding did not
cause both a reactor trip and the loss of mitigation equipment relied upon to transition the
plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss
of feed water). The inspectors determined that there was no cross-cutting aspect
associated with this finding because the cause of the performance deficiency occurred
more than three years ago, and was not representative of present plant performance.
(Section 1R12)
Green. A self-revealing Green NCV of Technical Specification (TS) 6.8.1.a, Procedures
and Programs, was identified for PSEGs failure to follow procedure MA-AA-1000,
Maintenance Standards and Practices, during the replacement of Bailey logic modules
(LM) associated with the D vital bus (10A404). Specifically, during the spring 2009
Enclosure
4
refueling outage (1R15), PSEG failed to follow a work order (WO) requiring the replacement
of all Bailey logic modules listed in WO 60061175 with new logic modules. As a result, a
logic module (H1PB-1PBXIS-DC652010302) for the D vital bus was not replaced during
1R15, and failed due to age on December 19, 2013, causing a loss of the vital bus and an
entry into the associated 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Technical Specification Action Statement (TSAS) 3.8.3.1
for Onsite Power Distribution Systems. PSEGs corrective actions included replacement of
the failed logic module, performance of an extent of condition inspection to ensure other
similar logic modules and relays were replaced, and reinforcement of proper maintenance
practices with the individuals involved in the completion of WO 60061175.
The performance deficiency was determined to be more than minor because it was
associated with the human performance attribute of the Initiating Events cornerstone, and
adversely affected the cornerstone objective to limit the likelihood of events that upset plant
stability and challenge critical safety functions during shutdown as well as power
operations. Specifically, not following the work order instructions resulted in an extended
service duration and failure of a component that resulted in a loss of power to the D vital
bus on December 19, 2013. Similarly, this performance deficiency was also similar to
examples 2.g and 4.b of NRC IMC 0612, Appendix E, in that PSEG is required to follow
their procedures per TS 6.8.1, and ultimately led to a safety impact given the failure of the
logic module causing a loss of power to the 10A404 vital bus. The inspectors determined
the finding to be of very low safety significance (Green) in accordance with Exhibit 1 of NRC
IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power,
dated June 19, 2012, because the finding involved the loss of a support system that
contributes to the likelihood of an initiating event (Loss of an AC Bus), but did not affect
mitigation equipment. The inspectors determined that there was no cross-cutting aspect
associated with this finding because the cause of the performance deficiency occurred
more than three years ago, and was not representative of present plant performance.
(Section 1R13)
Green. A self-revealing finding of very low safety significance (Green) was identified when
PSEG failed to ensure that appropriate contingency actions were in place prior to the
performance of A MS emergency level controller tuning as required by WC-AA-105, Work
Activity Risk Management. Specifically, the decision to tune the emergency level controller
without appropriate contingencies in place led to a turbine trip on high A MS level and
subsequent reactor scram on December 5, 2013. PSEGs corrective actions included
conducting performance management with the individuals involved with the tuning evolution
and revising the moisture separator drain tank level tuning procedure to require an
individual at the normal and emergency controllers when performing emergency level
controller tuning.
This finding was more than minor because it was associated with the human performance
attribute of the Initiating Events cornerstone, and adversely affected the cornerstone
objective to limit the likelihood of events that upset plant stability and challenge critical safety
functions during shutdown as well as power operations. The inspectors determined that this
finding was of very low safety significance (Green) using Exhibit 1 of NRC IMC 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated
June 19, 2012, because the finding did not cause both a reactor trip and the loss of
mitigation equipment relied upon to transition the plant from the onset of the trip to a stable
shutdown condition (e.g. loss of condenser, loss of feed water). The inspectors determined
that the finding had a cross cutting aspect in the Human Performance area associated with
Work Management, because PSEG personnel did not implement a process of planning,
Enclosure
5
controlling, and executing work activities such that nuclear safety is the overriding priority.
Specifically, technicians were only stationed at the emergency level controller during the
tuning, when having technicians at both controllers would have provided more time to
recover from a high level condition in the A MS, and may have prevented the turbine trip
and subsequent reactor scram on December 5, 2013. [H.5] (Section 4OA3)
Cornerstone: Mitigating Systems
Green. The inspectors identified a Green NCV of TS 6.8.1.a, Procedures because PSEG
procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could potentially complicate an
internal flooding event and adversely affect assumptions in Hope Creeks flood design.
Specifically, the procedures did not ensure operator response would not communicate the
high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) watertight
rooms and potentially render two safety-significant single train systems inoperable. In
addition to entering the issue into the corrective action program (CAP) as NOTFs
20646334, 20646335 and 20620653586, PSEGs corrective actions include a planned
revision of the annunciator response procedures and issuance of a standing order to the
Operations department staff.
The performance deficiency is more than minor because it was associated with the
procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the
cornerstone objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences (i.e., core damage).
Specifically, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could
potentially complicate an internal flooding event and adversely affect assumptions in Hope
Creeks flood design, since the procedures did not ensure operator response would not
communicate the HPCI and RCIC watertight rooms and potentially render multiple trains of
safety-related SSCs inoperable. This performance deficiency was also similar to examples
3.j and 3.k of NRC IMC 0612, Appendix E, in that communicating the two watertight rooms
created a reasonable doubt of operability of the HPCI and RCIC systems. PSEG plans to
perform a detailed technical evaluation to evaluate the impact of internal flood propagation
in the HPCI and RCIC rooms. The finding was evaluated in accordance with Exhibits 2 and
4 of NRC IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012.
Since opening the watertight door during an internal flooding event could bypass the flood
protection feature and potentially degrade two or more trains of a multi-train system or
function, a detailed risk assessment was performed. The finding was determined to be of
very low safety significance (Green). Since the change in core damage frequency was
sufficiently low, no further evaluation for large early release was required. The inspectors
determined that the finding had a cross cutting aspect in the Human Performance area
associated with Training, in that PSEG did not provide adequate training and ensure
knowledge transfer to maintain a knowledgeable, technically competent workforce and instill
nuclear safety values. Specifically, operator training did not ensure operator response to
internal flooding would not result in communicating two watertight rooms containing safety
significant single-train systems. [H.9] (Section 1R06)
Enclosure
6
Cornerstone: Barrier Integrity
Green. The inspectors reviewed a Green self-revealing NCV of Title 10 of the Code of
Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, for
PSEGs failure to effectively implement the design change process. Specifically, PSEGs
design change package (DCP) 4EC-3662 failed to reclassify the purchase classification
(PC) of the main control room (MCR) chiller pressure control valve (PCV) positioner from
non-safety related (PC4) to safety related (PC1). Because of the incorrectly assigned PC,
PSEG did not track the shelf life of replacement positioner diaphragms, which led to the
failure of the A MCR positioner on December 20, 2013. PSEGs corrective actions included
replacement of the failed positioner and changing the purchase classification for the chiller
PCV positioners to safety-related (PC1). Since the implementation of DCP 4EC-3662 in
1997, the DCP procedures have been enhanced to ensure the completion of a purchase
class evaluation of procured materials that are implemented in the design change process.
The inspectors determined that the performance deficiency was more than minor because
it is associated with the design control attribute of the Barrier Integrity cornerstone, and
adversely affected the cornerstone objective of maintaining the radiological barrier
functionality of the control room. In accordance with Exhibit 3 of NRC IMC 0609, Appendix
A, The Significance Determination Process (SDP) for Findings at Power, issued June 19,
2012, the inspectors determined that this finding is of very low safety significance (Green)
because the performance deficiency represents a degradation of only the radiological barrier
function provided for the control room. The inspectors determined that there was no cross-
cutting aspect associated with this finding because the cause of the performance deficiency
occurred more than three years ago, and was not representative of present plant
performance. (Section 4OA3)
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
corrective action program. This violation and corrective action tracking number are listed in
Section 4OA7 of this report.
Enclosure
7
REPORT DETAILS
Summary of Plant Status
Hope Creek Generating Station began the inspection period at full rated thermal power (RTP).
On April 1, 2014, Hope Creek conducted a planned down power to 50 percent of RTP to
support power suppression testing (PST), main turbine valve testing and main condenser water
box cleaning. The unit was returned to full RTP on April 4, 2014. On May 14, 2014, the B
reactor recirculation pump (RRP) speed unexpectedly rose to its maximum value. Operators
took manual control of the pump and reduced the pump speed to less than reactor recirculation
flow TS requirements. On May 23, 2014, operators reduced power to 98 percent to perform B
RRP speed control circuit corrective maintenance. Operators returned the unit to full power on
the same day. On May 28, 2014, Hope Creek conducted a planned down power to 50 percent
of RTP to support main turbine valve testing and main condenser water box cleaning. The unit
was returned to full RTP on May 31, 2014, and remained at or near full 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 - 2 samples)
.1 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors performed a review of PSEGs readiness for the onset of seasonal high
temperatures. The review focused on the safety auxiliaries cooling system (SACS) and
station service water (SSW) system. The inspectors reviewed the Updated Final Safety
Analysis Report (UFSAR) and TS 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 verify that no
unidentified issues existed that could challenge the operability of the systems during hot
weather conditions. Documents reviewed for each section of this inspection report are
listed in the Attachment.
b. Findings
No findings were identified.
.2 External Flooding
a. Inspection Scope
During the week of May 24, 2014, the inspectors performed an inspection of the external
flood protection measures for Hope Creek. The inspectors reviewed procedures, design
documents, and the UFSAR, Chapters 2.4.2, Floods, and 3.4, Water Level (Flood)
Design, which described the design flood levels and protection areas containing safety-
Enclosure
8
related equipment to identify areas that may be affected by flooding. The inspectors
also reviewed the limiting conditions for operations and the surveillance requirements in
TS 3.7.3, Flood Protection. The inspectors review focused on the Hope Creek Unit 1
areas, which protect Unit 1 equipment, that are susceptible to external flooding.
Specifically, the inspectors walked down the south, east and west walls of the reactor
building 102, 77, and 54 elevations. The inspectors inspected the condition of the
walls and ensured that any outside penetrations susceptible to external flooding were
flood protected. The inspectors also inspected the flood doors present in that area,
which are listed in TS Table 3.7.3-1, Perimeter Flood Doors. The inspectors verified
that the doors were in conformance with plant maintenance procedures and drawings.
The inspectors reviewed the preventive maintenance activities performed on these doors
with the responsible system engineer. The inspectors also conducted a walkdown of
these doors to verify that the doors were in conformance with the design basis
requirements in the UFSAR, the TS, and plant procedures and drawings. Additionally,
the inspectors reviewed the abnormal operating procedure, HC.OP-AB.MISC-0001,
Acts of Nature, for mitigating external flooding during severe weather to determine if
PSEG had planned or established adequate measures to protect against external
flooding events.
b. Findings
No findings were identified.
1R04 Equipment Alignment
Partial System Walkdowns (71111.04 - 3 samples)
a. Inspection Scope
The inspectors performed partial walkdowns of the following systems:
RCIC during HPCI booster pump planned maintenance on May 2, 2014
D emergency diesel generator (EDG) area ventilation system tornado dampers
during A EDG planned maintenance the week of May 6, 2014
A, B, and D SSW pumps during C SSW pump planned maintenance on June 2,
2014
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, technical specifications,
work orders, condition reports, and the impact of ongoing work activities on redundant
trains of equipment in order to identify conditions that could have impacted system
performance of their 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
corrective action program for resolution with the appropriate significance
characterization.
Enclosure
9
b. Findings
No findings were identified.
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.
Review of compensatory measure fire watch for 10C467 fire protection panel power
supply failure on April 17, 2014
FRH-II-415, Revision 4, Hope Creek Pre-Fire Plan, drywell pad torus area on April
21, 2014
FRH-II-412, Revision 3, Hope Creek Pre-Fire Plan, RCIC pump and turbine room
and electrical equipment room, on May 20, 2014
FRH-II-532, Revision 6, Hope Creek Pre-Fire Plan, lower control equipment room, on
May 23, 2014
FRH-II-542, Revision 9, Hope Creek Pre-Fire Plan, control equipment mezzanine, on
May 23, 2014
b. Findings
No findings were identified.
.2 Fire Protection - Drill Observation (71111.05A - 1 sample)
a. Inspection Scope
The inspectors observed an unannounced fire brigade drill scenario conducted on
April 7, 2014, that involved a fire in the Hope Creek radwaste area, room 3351. The
inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors
verified that PSEG personnel identified deficiencies; openly discussed them in a self-
critical manner at the post-drill debrief; and took appropriate corrective actions as
required. The inspectors evaluated specific attributes as follows:
Proper wearing of turnout gear and self-contained breathing apparatus
Proper use and layout of fire hoses
Employment of appropriate fire-fighting techniques
Sufficient fire-fighting equipment brought to the scene
Effectiveness of command and control
Enclosure
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Search for victims and propagation of the fire into other plant areas
Smoke removal operations
Utilization of pre-planned strategies
Adherence to the pre-planned drill scenario
Drill objectives met
The inspectors also evaluated the fire brigades actions to determine whether these
actions were in accordance with PSEGs fire-fighting strategies.
b. Findings
No findings were identified.
1R06 Flood Protection Measures (71111.06 - 1 sample)
Internal Flooding Review
a. Inspection Scope
The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to
assess susceptibilities involving internal flooding. The inspectors also reviewed the
corrective action program to determine if PSEG identified and corrected flooding
problems and whether operator actions for coping with flooding were adequate. The
inspectors also focused on the A residual heat removal (RHR) pump room (4113), the
B RHR pump room (4109), the C RHR pump room (4114), the HPCI pump and turbine
room (4111), and the RCIC pump and turbine room (4110) to verify the adequacy of
penetration seals located below the flood line, watertight door seals, common drain lines
and sumps, and room level alarms.
b. Findings
Introduction. The inspectors identified a Green NCV of TS 6.8.1.a, Procedures
because PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could
potentially complicate an internal flooding event and adversely affect assumptions in
Hope Creeks flood design. Specifically, the procedures did not ensure operator
response would not communicate the HPCI and RCIC watertight rooms and potentially
render two safety-significant single train systems inoperable.
Description. During a review of flood protection measures for the 54 foot elevation of the
reactor building, inspectors questioned whether execution of flooding procedures could
impact the assumption of the flood analysis, which assumes that the A, B, and C
RHR pump rooms, the HPCI pump and turbine room, and the RCIC pump and turbine
room are protected. Specifically, inspectors determined that in response to a room
flooding alarm, the procedures directed operators to enter the rooms to investigate the
flooding and assess the extent of flooding, an action which could allow communication
between two watertight rooms.
Hope Creeks UFSAR section 3.6, Protection Against Dynamic Effects Associated with
the Postulated Rupture of Piping, states in part that, The postulated failure of a
Enclosure
11
moderate energy line can at most affect only the operations of one train of a redundant
safety-related system due to the provisions for physical separation of redundant trains.
Inspectors reviewed procedural actions that would be taken in response to flood alarms
for the HPCI pump and turbine room (Room 4111) and the RCIC pump and turbine room
(Room 4110). The alarm response procedures for the HPCI and RCIC room flood
alarms direct operators to dispatch an equipment operator to the applicable room to
investigate and confirm the floor level alarm and enter HC.OP-EO.ZZ-0103/4, Reactor
Building and Radioactive Release Control. HC.OP-EO.ZZ-0103/4 provides an entry
condition of any reactor building room floor level above 1 inch, which is also the setpoint
of the level alarm. The procedure directs operators to use all available sump pumps and
isolate all systems discharging into the room.
Since the procedures direct operators to investigate and confirm flooding, the inspectors
assessed the ability of operators to enter the room without affecting equipment in an
adjacent room. Each of the ECCS/RCIC rooms are separated by large watertight doors
with no window or portal to monitor conditions on the other side of the door without
opening the door. The inspectors noted that the alarm response procedures for a high
level alarm in the A and B RHR pump rooms direct control room operators to dispatch
an equipment operator to enter the RHR pump rooms at their upper levels (77 foot
elevation) to determine the cause of the alarm. This procedural direction would prevent
flood propagation to the adjacent HPCI and RCIC electrical rooms.
The HPCI and RCIC rooms are located next to one another and are connected by a
watertight door. For a flood in the HPCI room, since both doors to the room open into
the adjacent rooms (i.e., water pressure would aid in opening the door), once the door
was unlatched, the water would force the door open and flood the adjacent room. The
inspectors noted that the alarm response procedures for potential flooding in the HPCI
and RCIC rooms do not provide direction on where to access the HPCI and RCIC rooms
when investigating for a potential flood condition. Therefore, when executing the
procedure to respond to flooding in the HPCI room, operators could propagate an
internal flood to two watertight rooms if they were to access the HPCI room through the
door connecting HPCI and RCIC.
The inspectors interviewed the Hope Creek emergency operating procedure (EOP)
coordinator regarding operator actions in response to indications of a flood in the HPCI
and RCIC rooms and the HC.OP-EO.ZZ-0103/4 procedure. Interviews with the EOP
coordinator indicated that operator knowledge would ensure proper access to the HPCI
and RCIC rooms when investigating a potential flood. However, no operator training
could be found that specified that operators should not access the HPCI and RCIC
rooms using the connecting watertight door when responding to a potential flood
condition.
The inspectors interviewed a senior reactor operator and two equipment operators about
their response to alarms for a potential flood in the HPCI room. The senior reactor
operator did not indicate that he would direct which door to access the HPCI room. The
equipment operators indicated that they would access the HPCI room from the door to
the RCIC room because the floor drains in the RCIC room would better drain any flood
water.
In the absence of further engineering evaluation, there was reasonable doubt of the
operability of the HPCI and RCIC systems. Specifically, internal flood propagation from
Enclosure
12
the design internal flood in the HPCI room could result in a water level that calls the
operability of RCIC into question. PSEG plans to perform a detailed technical evaluation
to evaluate the impact of internal flood propagation in the HPCI and RCIC rooms in
response to the inspectors questions (Order 70167153). PSEG entered the issue into
the CAP as NOTFs 20646334, 20646335, and 20653586. PSEGs corrective actions
include a planned revision of the annunciator response procedures and issuance of a
standing order to the Operations department staff.
Analysis. The inspectors determined that PSEGs failure to provide adequate procedural
guidance to respond to a HPCI/RCIC room flood alarm was a performance deficiency
that was within PSEGs ability to foresee and correct, and should have been prevented.
The performance deficiency is more than minor because it was associated with the
procedure quality attribute of the Mitigating Systems cornerstone, and adversely affected
the cornerstone objective to ensure the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences (i.e., core
damage). Specifically, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022
could potentially complicate an internal flooding event and adversely affect assumptions
in Hope Creeks flood design, since the procedures did not ensure operator response
would not communicate the HPCI and RCIC watertight rooms and potentially render
multiple trains of safety-related SSCs inoperable. This performance deficiency was also
similar to examples 3.j and 3.k of NRC IMC 0612, Appendix E, in that communicating the
two watertight rooms created a reasonable doubt of operability of the RCIC system.
PSEG plans to perform a detailed technical evaluation to evaluate the impact of internal
flood propagation in the HPCI and RCIC rooms. The finding was evaluated in
accordance with Exhibits 2 and 4 of NRC IMC 0609, Appendix A, The SDP for Findings
At-Power, dated June 19, 2012. Since opening the watertight door during an internal
flooding event could bypass the flood protection feature and potentially degrade two or
more trains of a multi-train system or function, a detailed risk assessment was
performed.
The condition was modeled using the Hope Creek SPAR model version 8.18 along with
SAPHIRE version 8.09. As a bounding analysis, the condition was assumed to exist for
greater than one year and the flooding was assumed to require a reactor shutdown,
which results in a plant transient with failure of HPCI and RCIC due to flood impacts.
The flooding initiating event frequency was derived from the Hope Creek Internal Flood
Report, HC-PRA-012, Revision 2. The resulting change in core damage frequency was
substantially less than 1E-7. The dominant sequences included a transient with a failure
to depressurize along with RCIC and HPCI failures. Since the change in core damage
frequency was sufficiently low, no further evaluation for large early release was required.
The inspectors determined that the finding had a cross-cutting aspect in the Human
Performance area associated with Training, in that PSEG did not provide adequate
training and ensure knowledge transfer to maintain a knowledgeable, technically
competent workforce and instill nuclear safety values. Specifically, operator training did
not ensure operator response to internal flooding would not communicate the HPCI and
RCIC watertight rooms and potentially render multiple trains of safety-related SSCs
inoperable. [H.9].
Enforcement. TS 6.8.1.a, Procedures and Programs, requires in part, that written
procedures recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2,
shall be established, implemented, and maintained. RG 1.33, Revision 2, Appendix A,
Enclosure
13
Section 5, requires that each safety-related annunciator should have its own written
procedure, which should normally contain the immediate operation action. PSEG
procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 provide direction for operator
response to indications of high level in the HPCI and RCIC rooms. Contrary to the
above, until implementation of Operations Department Standing Order 2014-26 on
May 24, 2014, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 were
inadequate in that actions directed in the procedures could complicate an internal
flooding event and potentially adversely affect assumptions in Hope Creeks flood
design. In addition to entering the issue into the CAP as NOTFs 20646334, 20646335,
and 20653586, PSEGs corrective actions include a planned revision of the annunciator
response procedures and issuance of a standing order to the Operations department
staff. Because this violation was of very low safety significance (Green), and PSEG
entered this issue into their CAP, this violation is being treated as an NCV, consistent
with Section 2.3.2 of the Enforcement Policy. (NCV 05000354/2014003-01, Inadequate
Procedural Guidance for Responding to an Internal Flooding Event in the HPCI
and RCIC Rooms)
1R11 Licensed Operator Requalification Program (71111.11Q - 2 samples)
.1 Quarterly Review of Licensed Operator Requalification Testing and Training
a. Inspection Scope
The inspectors observed licensed operator simulator training on April 28, 2014, that
included an A RRP trip, reactor water cleanup (RWCU) system leak, loss of main
condenser vacuum, and an anticipated transient without scram. The inspectors
evaluated operator performance during the simulated event and verified completion
of critical tasks, 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. Additionally, the inspectors assessed the ability of the training staff to
identify and document crew performance problems.
b. Findings
No findings were identified
.2 Quarterly Review of Licensed Operator Performance in the Main Control Room
a. Inspection Scope
The inspectors observed a planned down power to support PST to locate a potential fuel
defect and the conduct main turbine valve testing on April 1, 2014. The inspectors
observed reactivity manipulations to verify that procedure use and crew communications
met established expectations and standards. The inspectors observed pre-job briefings
to verify that the briefings met the criteria specified in OP-AA-101-111-1004 Operations
Standards, Revision 4, and HU-AA-1211, Pre-Job Briefings, Revision 11. Additionally,
the inspectors observed the performance of turbine valve testing surveillance test,
HC.OP-ST.AC-0002, on April 1, 2014, to verify that procedure use, crew
Enclosure
14
communications, and coordination of activities between work groups similarly met
established expectations and standards.
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 structure, system, or component (SSC) performance and
reliability. The inspectors reviewed corrective action program documents (notifications),
maintenance work orders (orders), and maintenance rule basis documents to ensure
that PSEG was identifying and properly evaluating performance problems within the
scope of the maintenance rule. As applicable, the inspectors verified that the SSC was
properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified
that the (a)(2) performance criteria established by PSEG staff was reasonable; for SSCs
classified as (a)(1), the inspectors assessed the adequacy of goals and corrective
actions to return these SSCs to (a)(2); and, the inspectors independently verified that
appropriate work practices were followed for the SSCs reviewed. Additionally, the
inspectors ensured that PSEG staff was identifying and addressing common cause
failures that occurred within and across maintenance rule system boundaries.
A MS drain and dump valve functional failure determinations for December 1 and 5,
2013, scrams (Order 70161698)
Salem Unit 3 (gas turbine generator) scoping in Hope Creek maintenance rule
program (NOTF 20502118)
RCIC nuclear management and control leak detection system card failure and
replacement on May 23, 2014 (Order 60113250)
b. Findings
Introduction. A self-revealing finding of very low safety significance (Green) was
identified for PSEGs failure to evaluate an identified deficiency in accordance with
PSEG procedure LS-AA-125, Corrective Action Program. Specifically, PSEG failed to
take self-recommended actions in NOTF 20447050 to evaluate the B MS dump valve
performance after failing to operate as designed during B MS drain valve trouble-
shooting on January 11, 2010. As a result, PSEG did not identify and correct a potential
design flaw associated with thermal binding of the MS dump valves, which was
determined to be the cause of the A MS dump valve failing to stroke open on
December 1, 2013, causing a reactor scram from 100 percent power.
Description. Hope Creek utilizes two horizontal non-reheat MS vessels that remove
moisture in the steam from the high pressure turbine exhaust before it enters the low
pressure turbine which prevents damage to the low pressure turbines. The condensate
that is collected in the MS is drained to the 5A, 5B, and 5C feed water heaters where it
eventually drains to the condenser. If the water level in the MS becomes too high and
the normal MS level control drain valves are not able to drain it, then the dump valve
opens draining the water in the MS directly to the condenser.
Enclosure
15
At 6:07 am on December 1, 2013, while operating at 100 percent power, the A MS
normal drain level reached a maximum allowed value of 70 percent allowing the MS
dump valve to cycle to control level. After six minutes (~15 cycles of the A dump valve
going open and shut) of successfully controlling MS level in the dump valve range, the
A MS dump closed and failed to re-open causing high level in the A MS, a turbine trip
and a reactor scram.
On December 5, 2013, a second reactor scram occurred at 75 percent power during A
MS dump valve tuning with the normal A MS drain valves failed closed to support
emergency level controller tuning. The A MS dump valve again failed to stroke open
when expected causing high MS level.
PSEG conducted a root cause evaluation (Order 70161698) to determine the cause of
the A MS drain and dump valve issues leading to the December 1 and December 5,
2013, scrams. PSEG determined that the A MS dump valve experienced thermal
binding because both PSEG and the valve manufacturer did not recognize the potential
for these valves to experience thermal binding. The results from PSEGs evaluation
concluded that the A MS dump valve design is susceptible to internal binding due to
differential expansion, resulting in the valve plug sticking in the valve cage.
During the timeline review for the A MS root cause evaluation, PSEG discovered that
the B MS dump valve did not open as expected on January 11, 2010, when trouble-
shooting B MS drain valve control issues. The dump valve had cycled multiple times
prior to PSEG removing air to reopen the B MS dump valve when MS level was rising
during drain valve control troubleshooting and the dump valve did not open for 12
minutes. The condition of the B MS dump valve not operating as expected was
documented under NOTF 20447050. The NOTF documented that the B MS dump
valve had cycled several times prior to the failure to open and recommended that the
B MS dump valve performance be evaluated and implement corrective actions as
necessary. This NOTF was not properly allocated to the equipment apparent cause
evaluation (EQACE) that was created (Order 70105948) to evaluate the B MS drain
valve control troubleshooting and therefore was never evaluated. PSEG created NOTF
20640526 to document the missed opportunity to troubleshoot B MS dump valve
performance and identify the thermal binding issue when the valve is cycled at normal
reactor power and pressure.
LS-AA-125, Corrective Action Program, Revision 12, Section 3.5.6 (effective on
January 11, 2010) states to ensure that the corrective action identified have been
agreed upon by the assignees and that the corrective actions are appropriately entered
into the CR database. Based on this information, the inspectors concluded that PSEG
failed to ensure that EQACE 70105948 addressed the identified issue in NOTF
20447050 recommending that the B MS dump valve performance on January 11, 2010,
be evaluated and corrected. PSEG has entered the above concerns into the CAP as
20640526. PSEGs corrective actions include a design change to the MS emergency
level control system that eliminates dump valve cycling on high MS level.
Analysis. PSEGs failure to ensure evaluations addressed identified issues in
accordance with PSEG procedure LS-AA-125, Corrective Action Program, was a
performance deficiency which was reasonably within PSEGs ability to foresee and
correct and should have been prevented. The performance deficiency was determined
Enclosure
16
to be more than minor because it was associated with the equipment performance
attribute of the Initiating Events cornerstone, and adversely affected the cornerstone
objective to limit the likelihood of events that upset plant stability and challenge critical
safety functions during shutdown as well as power operations. The inspectors
determined that this finding was of very low safety significance using Exhibit 1 of NRC
IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-
Power, dated June 19, 2012, because the finding did not cause both a reactor trip and
the loss of mitigation equipment relied upon to transition the plant from the onset of the
trip to a stable shutdown condition (e.g. loss of condenser, loss of feed water). The
inspectors determined that there was no cross-cutting aspect associated with this finding
because the cause of the performance deficiency occurred more than three years ago,
and was not representative of present plant performance.
Enforcement. This finding does not involve enforcement action because no violation of a
regulatory requirement was identified. Since this finding does not involve a violation and
is of very low safety significance (Green), it is identified as a FIN. (FIN
05000354/2014003-02, Failure to Evaluate an Identified Issue with the Moisture
Separator Dump Valve Performance)
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 technical
specification requirements and inspected portions of redundant safety systems, when
applicable, to verify risk analysis assumptions were valid and applicable requirements
were met.
Unplanned de-energization and loss of the D vital bus on December 19, 2013
Planned high risk activity to perform main turbine combined intermediate valve
testing on April 2, 2014
Planned high risk activity to perform power suppression testing to locate a fuel defect
on April 2, 2014
B RRP isolator replacement due to un-demanded speed changes on May 22, 2014
B RHR system and F filtration, recirculation, and ventilation system recirculation
fan planned maintenance on June 11, 2014
b. Findings
Introduction. A Green self-revealing NCV of TS 6.8.1.a, Procedures and Programs,
was identified for PSEGs failure to follow procedure MA-AA-1000, Maintenance
Enclosure
17
Standards and Practices, during the replacement of Bailey logic modules associated
with the D vital bus (10A404). Specifically, during the spring 2009 refueling outage
(1R15), PSEG failed to follow a WO requiring the replacement of all Bailey logic modules
listed in WO 60061175 with new logic modules. As a result, a logic module (H1PB-
1PBXIS-DC652010302) for the 10A404 vital bus was not replaced during 1R15, and
failed due to age on December 19, 2013, causing a loss of the 10A404 bus and an entry
into the associated 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> TSAS 3.8.3.1 for Onsite Power Distribution Systems.
Description. The PSEG Class 1E AC power distribution system provides a reliable
source of power for all Class 1E loads and distributes power at 4.16 kilovolt (kV), 480
volt (V), and 208/120 V. The system is divided into four independent channels and each
channel supplies power to loads in its own load group. Each of the four vital buses is
provided with connections to the two offsite power sources through two in-feed breakers
(40401 and 40408). One of these breakers is designated as the normal source and the
other as the alternate source for the bus. In addition to these two connections to offsite
power, each of the vital buses is connected to its dedicated EDG. These EDGs serve as
the standby electric power source for their respective channels in case both the normal
and alternate power supplies to a bus are lost.
At 3:11 pm on December 19, 2013, PSEG was performing a normally planned swap of
the 10A404 in-feed breakers from 40408 to 40401, when both in-feed breakers tripped
open and de-energized the 10A404 bus. PSEG stabilized the plant, entered the
associated 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> TSAS 3.8.3.1, conducted troubleshooting, performed component
replacements, and returned the 10A404 vital bus to service at 5:01 pm on December 19,
2013.
Following the restoration of the 10A404 vital bus on December 19, 2013, PSEG
conducted an EQACE documented under order 70162013. This EQACE determined
that the apparent cause of the 10A404 vital bus loss was an age-related failure of a logic
module (H1PB-1PBXIS-DC652010302) that was not replaced, but mistakenly
documented as being replaced in 2009 per WO 60061175. PSEG determined that the
independent peer check verification performed for both the LM removal and LM
installation failed to ensure that the serial number for the removed LM (H1PB-1PBXIS-
DC652010302) was not reinstalled into the system. Because this logic module was not
replaced in 2009, and remained in the system for 4 years past its vendor recommended
lifetime of 20 years, PSEG determined that it failed due to age and could not provide an
output to allow the 10A404 bus 40408 in-feed breaker to trip normally during the planned
in-feed breaker swap on December 19, 2013.
The inspectors reviewed PSEGs procedures for conducting the 10A404 in-feed breaker
swaps, operations narrative logs, and the completed EQACE 70162013 for the
December 19, 2013, event. PSEG procedure MA-AA-1000, Section 3.0, Maintenance
Standards and Practices, states in part, that all work on plant SSCs will be performed
using appropriate documentation such as work orders, notifications, or applicable
troubleshooting process control forms. Both the current revision of this procedure
(Revision 14) and the revision in use during 1R15 (Revision 7) have this language
requiring all work be performed in accordance with the appropriate documentation.
The inspectors determined that PSEG failed to follow this procedure by not complying
with WO 60061175 for the replacement of Bailey cards for the 10A404 in-feed breakers
during 1R15. This WO stated, in part, to Replace all Logic Modules listed with new
modules, and the list contained included the 10A404 in-feed breaker logic module
Enclosure
18
(H1PB-1PBXIS-DC652010302 LM 4.16 KV MAIN BKR 52-40401). Contrary to this,
PSEGs review of the serial number on the failed logic module and WO 60061175
showed that the original logic module was re-installed following its removal during the
conduct of maintenance. As part of the extent of condition for PSEGs EQACE, a review
of all other similar logic modules found them replaced as documented.
PSEG initiated NOTF 20639519 and EQACE 70162013 in the CAP to replace the failed
logic module, identify other similar logic modules and relays that may not have been
replaced or may not have an associated maintenance plan, and reinforce proper
maintenance practices to the individuals involved in the completion of WO 60061175.
Analysis. PSEGs failure to follow procedure MA-AA-1000 for Maintenance Standards
and Practices during the replacement of a Bailey logic module associated with the
10A404 vital bus represented a performance deficiency that was reasonably within
PSEGs ability to foresee and correct and should have been prevented. The
performance deficiency was determined to be more than minor because it was
associated with the human performance attribute of the Initiating Events cornerstone,
and adversely affected the cornerstone objective to limit the likelihood of events that
upset plant stability and challenge critical safety functions during shutdown as well as
power operations. Specifically, not following the work order instructions resulted in an
extended service duration and failure of a component that resulted in a loss of power to
the D vital bus on December 19, 2013. Similarly, this performance deficiency was also
similar to examples 2.g and 4.b of NRC IMC 0612 Appendix E, in that PSEG is required
to follow its procedures per TS 6.8.1, and ultimately led to a safety impact given the
failure of the logic module causing a loss of power to the 10A404 vital bus. The
inspectors determined the finding to be of very low safety significance (Green) in
accordance with Exhibit 1 of NRC IMC 0609, Appendix A, The Significance
Determination Process for Findings At-Power, dated June 19, 2012, because the finding
involved the loss of a support system that contributes to the likelihood of an initiating
event (Loss of an AC Bus), but did not affect mitigation equipment.
The inspectors determined that there was no cross-cutting aspect associated with this
finding because the cause of the performance deficiency occurred more than three years
ago, and was not representative of current plant performance.
Enforcement. TS 6.8.1.a, Procedures and Programs, requires in part, that written
procedures recommended in Appendix A of RG 1.33, Revision 2, shall be established,
implemented, and maintained. Section 9.a of RG 1.33, Revision 2, Appendix A, requires
that maintenance that can affect the performance of safety-related equipment should be
properly preplanned and performed in accordance with written procedures, documented
instructions, or drawings appropriate to the circumstances. Section 3.0 of PSEG
procedure MA-AA-1000, Maintenance Standards and Practices, states in part, that all
work on plant SSCs will be performed using appropriate documentation such as work
orders, notifications, or applicable troubleshooting process control forms.
Contrary to the above, on April 16, 2009, PSEG failed to follow this procedure during the
replacement of a Bailey logic module associated with the 10A404 vital bus. Specifically,
PSEG failed to follow WO 60061175 which required the replacement of all Bailey logic
modules listed in the WO with new logic modules. As a result, a logic module for the
10A404 vital bus was not replaced in 2009, and failed due to age on December 19,
2013, causing a loss of the 10A404 bus and an entry into the associated 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> TSAS
Enclosure
19
3.8.3.1 for Onsite Power Distribution Systems. PSEGs corrective actions included
replacement of the failed logic module, performance of an extent of condition inspection
to ensure other similar logic modules and relays were replaced, and reinforcement of
proper maintenance practices with the individuals involved in the completion of WO
60061175. Because this violation was of very low safety significance (Green) and was
entered into PSEGs CAP as NOTF 20639519 and EQACE 70162013, the violation is
being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.
(NCV 05000354/2014003-03, Failure to Follow Procedure Resulting in the Loss of a
Vital 4kV Bus)
1R15 Operability Determinations and Functionality Assessments (71111.15 - 5 samples)
a. Inspection Scope
The inspectors reviewed operability determinations for the following degraded or non-
conforming conditions:
Minimum Allowable Wall Thickness Evaluation of 4 D RHR Piping (Order
80108395)
C EDG operability with lost parts potentially in the main lube oil sump on April 7,
2014 (NOTF 20645519)
Standby liquid control event report #49909 retraction on April 15, 2014 (NOTFs
20647199 and 20643229)
B RRP undemanded speed changes on May 14, 2014 (NOTF 20651102)
Revision 3 of Masterpact Breaker failure analysis operability evaluation on May 28,
2014 (NOTF 20652187 and Order 70163760)
The inspectors selected these issues based on the risk significance of the associated
components and systems. The inspectors evaluated the technical adequacy of the
operability determinations to assess whether technical specification 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 technical specifications and UFSAR to
PSEGs evaluations to determine whether the components or systems were operable.
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. The inspectors determined, where appropriate,
compliance with assumptions in the evaluations.
b. Findings
No findings were identified.
Enclosure
20
1R18 Plant Modifications (71111.18 - 2 samples)
a. Inspection Scope
The inspectors reviewed the temporary modification listed below to determine whether
the modification affected the safety functions of systems that are important to safety.
The inspectors reviewed 10 CFR 50.59 documentation to verify that the temporary
modification did not degrade the design bases, licensing bases, and performance
capability of the affected systems.
Temporary Configuration Change Package (TCCP) 4HT-14-005 - Temporary
Repairs to the Condensate Storage Tank Dike Drain Line
b. Findings
No findings were identified.
.2 Permanent Modifications
a. Inspection Scope
The inspectors evaluated a modification to the RWCU system implemented by DCP
80111754, Masterpact Breaker Add Aux Contact with Close Coil. This DCP wires an
existing breaker auxiliary contact in series with the internal close coil to allow the close
coil to be de-energized after the breaker has closed rather than be continuously
energized. The existing configuration with the breaker close coil continuously energized
is allowing an intermittent failure of these breakers where they lock up and fail to re-
close when required per design. The inspectors verified that the design bases, licensing
bases, and performance capability of the affected systems were not degraded by the
modification. In addition, the inspectors reviewed modification documents associated
with the upgrade and design change, including the breaker operation. The inspectors
also reviewed revisions to the control room alarm response procedure and interviewed
engineering and operations personnel to ensure the procedure could be reasonably
performed.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing (71111.19 - 7 samples)
a. Inspection Scope
The inspectors reviewed the post-maintenance tests for the maintenance activities listed
below to verify that procedures and test activities ensured system operability and
functional capability. The inspectors reviewed the test procedure to verify that the
procedure adequately tested the safety functions that may have been affected by the
maintenance activity, that the acceptance criteria in the procedure was consistent with
the information in the applicable licensing basis and/or design basis documents, and that
the procedure had been properly reviewed and approved. The inspectors also
Enclosure
21
witnessed the test or reviewed test data to verify that the test results adequately
demonstrated restoration of the affected safety functions.
HPCI oil supply pressure gauge replacement on October 10, 2013 (Order 60113238)
B control room chilled water pressure control valve positioner and diaphragm
replacement on April 23, 2014 (Order 60116090)
10C467 fire protection panel power supply replacement on May 9, 2014 (Order
30269527)
B RRP pump speed controller card replacements on May 22, 2014 (Order
60117312)
RCIC nuclear management and control leak detection system card replacement on
May 23, 2014 (Order 60113250)
Service air compressor oil leak repair on June 5, 2014 (Order 60117447)
B RHR system relay replacements on June 11, 2014 (Orders 30098613 and
30098617)
b. Findings
No findings were identified.
1R22 Surveillance Testing (71111.22 - 9 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 technical
specifications, 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:
HC.OP-ST.AC-0002, Turbine Valve Testing quarterly surveillance on April 1, 2014
HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test on
April 7, 2014
HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - 0P204 and 0P217 -
In-service Test on April 9, 2014 (in-service test)
HC.MD-ST.PB-0003, Class 1E 4.16 kV Feeder Degraded Voltage Monthly
Instrumentation Channel Functional Testing of the B vital bus on April 15, 2014
HC.OP-IS.BC-0004, DP202, D Residual Heat Removal Pump In-Service Test on
April 22, 2014 (in-service test)
HC.OP-DL.ZZ-0026, Drywell floor drain leakage monitoring on May 1, 2014 (RCS
leakage)
HC.FP-ST.KC-0009, Diesel Driven Fire Pump Operability Test on May 6, 2014
HC.OP-IS.BC-0002, CP202, C Residual Heat Removal Pump In-Service Test on
June 25, 2014 (in-service test)
HC.OP-ST.KJ-0001, Emergency Diesel Generator 1AG400 Operability Test on
June 30, 2014
Enclosure
22
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 24,
2014 to identify any weaknesses and deficiencies in the classification, notification, and
protective action recommendation development activities. The inspectors observed
emergency response operations in the technical support center 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 corrective action program.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification (71151)
Reactor Coolant System (RCS) Specific Activity and RCS Leak Rate (2 samples)
a. Inspection Scope
The inspectors reviewed PSEGs submittal for the RCS specific activity and RCS leak
rate performance indicators for the period of April 1, 2013, through March 31, 2014. To
determine the accuracy of the performance indicator data reported during those periods,
the inspectors used definitions and guidance contained in NEI Document 99-02,
Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors
also reviewed RCS sample analysis and control room logs of daily measurements of
RCS leakage, and compared that information to the data reported by the performance
indicator. Additionally, the inspectors observed chemistry personnel taking and
analyzing an RCS sample.
b. Inspection Findings
No findings were identified.
Enclosure
23
4OA2 Problem Identification and Resolution (71152 - 1 sample)
.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 that PSEG entered issues into the corrective action program 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 screening of items entered into the corrective action
program and periodically attended condition report screening meetings.
b. Findings
No findings were identified.
.2 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a semi-annual review of site issues, as required by Inspection
Procedure 71152, Problem Identification and Resolution, to identify trends that might
indicate the existence of more significant safety issues. In this review, the inspectors
included repetitive or closely-related issues that may have been documented by PSEG
outside of the corrective action program, such as trend reports, performance indicators,
major equipment problem lists, system health reports, maintenance rule assessments,
and maintenance or corrective action program backlogs. The inspection also reviewed
PSEGs corrective action program database for the period of January 2014 to May 2014
to assess the notifications written as well as individual issues identified during the NRCs
daily condition report review (Section 4OA2.1). The inspectors reviewed the Hope
Creek station performance improvement integrated matrix (PIIM), conducted under
procedure LS-AA-125-1006, Performance Improvement Integrated Matrix, to verify that
PSEG personnel were appropriately evaluating and trending adverse conditions in
accordance with applicable procedures.
b. Findings and Observations
No findings were identified during this trend review.
The inspectors noted that PSEG personnel identified the following trends and entered
them into the corrective action program: an adverse trend in Appendix J leakage
(NOTFs 20632747, 20632748, 20632749); an adverse trend in design change package
quality (NOTFs 20642767 and 20644539); and an adverse trend in critical component
failures (NOTF 20638889). The inspectors also reviewed the 2013 third cycle Hope
Creek PIIM and the performance improvement action plan developed to improve station
performance in the areas of equipment reliability, decision making, and risk
management.
Enclosure
24
The inspectors noted a trend in the stations failure to perform cross-system
maintenance rule screenings:
When the feedwater crosstie valve (AE-HV-4144) failed, it was screened as not
a functional failure against the feedwater system. The condition was not
screened against the feedwater sealing functions of HPCI and RCIC.
The DD-411 battery room temperature was found above acceptance criteria. A
maintenance rule functional failure screening was performed for the functions of
the 1E 125 volt direct current (DC) system, but not for the auxiliary building
diesel area ventilation system.
As found setpoint failures of safety relief valves were screened against the
automatic depressurization system functions, but not against any of the main
steam system functions.
The inspectors determined this observation was not more than minor in accordance with
IMC 0612, because the observations did not result in any of the systems requiring
additional monitoring per 10 CFR 50.65(a)(1).
Based on the review of PSEGs trending, the inspectors concluded that PSEG was
appropriately identifying and entering issues into the corrective action program,
adequately evaluating the identified issues, and appropriately identifying adverse trends
before they become more safety significant problems.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153 - 6 samples)
.1 Plant Events
a. Inspection Scope
For the plant event listed below, the inspectors reviewed 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
Parts 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.
B RRP un-demanded speed change due to a failure in the speed controller, causing
a momentary increase in reactor power above the thermal power limit on May 15,
2014 (NOTF 20651102)
b. Findings
No findings were identified.
.2 Event Notification49909 Retraction, Standby Liquid Control System (SLC) Sample
Concentration Outside Technical Specification Limits
Enclosure
25
At 10:27 pm on March 12, 2014, PSEG was in the process of returning the SLC system
to service following planned maintenance on the B SLC pump when the MCR received
a SLC tank high level alarm (>4880 gallons). The MCR informed the equipment
operator conducting the SLC system restoration of the unexpected SLC tank high level
alarm and the operator closed a valve that had just been opened, which stopped the rise
in SLC storage tank level at 4926 gallons. PSEGs sample analysis of the SLC system
tank yielded a sodium pentaborate concentration outside the TS limits, rendering both
subsystems inoperable. The concentration was found to be at 13.598% by weight,
below the required concentration of 13.6% by weight. As part of the corrective actions,
PSEG restored the concentration to within TS limits and conducted an apparent cause
evaluation.
This condition was reported under 10 CFR 50.72(b)(3)(v)(D) on March 13, 2014, as
a condition that could have prevented the fulfillment of a safety function required to
mitigate the consequences of an accident (EN 49909). On April 14, 2014, PSEG
retracted EN 49909 stating that a subsequent review of the analytical data has
determined that the SLC tank sample met the TS requirement for operability (13.6
weight percent) and therefore, there was no reportable condition. The inspectors
reviewed PSEGs EN and EN retraction, apparent cause evaluation report, supporting
documentation including multiple NOTFs and technical evaluation (Order 70166989),
station procedures, and interviewed several members of station staff and management
regarding the event. No findings were identified during this review.
.3 (Closed) Licensee Event Report (LER) 05000354/2013-007-00, As-Found Values for
Safety Relief Valve Lift Set Points Exceed Technical Specification Allowable Limit
On November 22, 2013, PSEG received test results indicating that the as-found lift
setpoints for 5 of 14 main steam safety relief valves (SRVs) failed to open within the
required TS actuation pressure setpoint tolerance. TS 3.4.2.1 provides an allowable
pressure band of +/- 3 percent for each SRV. All five of the SRVs opened above the
required pressure band. PSEG determined that the apparent cause for the A, D, F,
K, and L SRV setpoint failures was corrosion bonding/sticking between the mating
surfaces of the pilot disc. These issues were placed into the CAP as NOTF 20631351.
The pilot assembly for each of the 14 SRVs has been replaced with a fully tested spare
assembly. Additionally, this LER stated PSEGs corrective actions include plans to
replace the currently installed SRVs with a new design that eliminates setpoint drift
events exceeding TS requirements and improves SRV reliability. Although this LER
reports the inoperability of five SRVs, this event did not result in a loss of system safety
function based on engineering analyses. These analyses showed that the SRVs would
have functioned to prevent a reactor vessel over-pressurization and that postulated
piping stresses would not exceed allowable limits. The enforcement aspects of this
finding are discussed in Section 4OA7. This LER is closed.
.4 (Closed) LER 05000354/2013-008-00 and LER 05000354/2013-008-01, Automatic
Actuation of the Reactor Protection System Due to a Main Turbine Trip
On December 1, 2013, Hope Creek Unit 1 automatically scrammed from 100 percent
rated thermal power due to a main turbine trip. The main turbine trip was due to high
level in the A MS. As a result of the scram, both RRPs tripped and three SRVs opened.
The plant was stabilized in hot shutdown, Operational Condition 3.
Enclosure
26
This condition is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted
in an automatic actuation of the reactor protection system. The inspectors reviewed
PSEGs LER and LER revision, root cause evaluation report (Order 70161698),
supporting documentation, station procedures, and interviewed several members of
station staff and management regarding the event. One finding was identified and is
discussed in Section 1R12 of this report. These LERs are closed.
.5 (Closed) LER 05000354/2013-009-00 and LER 05000354/2013-009-01, Automatic
Actuation of the Reactor Protection System Due to a Main Turbine Trip
a. Inspection Scope
On December 5, 2013, during tuning of the A MS emergency level controller, the
reactor automatically scrammed from 75 percent power due to a main turbine trip.
During the tuning activities, the A MS dump valve cycled repeatedly and subsequently
failed closed, resulting in high level in the A MS and subsequent turbine trip. The
automatic reactor scram resulted in a trip of both RRPs, as designed. During the
recovery of the RRPs, the digital electro-hydraulic control system was mis-operated
which caused the turbine bypass valves to cycle. This caused reactor level to swell
above Level 8 then shrink below Level 3, resulting in a second actuation of the reactor
protection system.
This condition is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in
an automatic actuation of the reactor protection system. The inspectors reviewed
PSEGs LER, root cause evaluation report (Order 70161698), supporting documentation,
station procedures, and interviewed several members of station staff and management
regarding the event. Two findings were identified and are discussed below. These
LERs are closed.
b. Findings
.1 Failure to Use Approved Method of Post-Scram Reactor Pressure Control
The mis-operation of the digital electro-hydraulic control system following the reactor
scram on December 5, 2013, has been previously evaluated. A self-revealing Green
NCV of TS 6.8.1.a (NCV 05000354/2014002-06) for Failure to Use Approved Method of
Post-Scram Reactor Pressure Control is documented in NRC Inspection Report
.2 Inadequate Implementation of Contingency Actions During Moisture Separator
Emergency Level Controller Tuning
Introduction. A self-revealing finding of very low safety significance (Green) was
identified when PSEG failed to ensure that contingency actions were appropriate for
the activity being performed prior to A MS emergency level controller tuning on
December 5, 2013. Specifically, the decision to tune the emergency level controller
without appropriate contingencies in place led to a turbine trip and subsequent reactor
scram on high A MS level.
Description. On December 5, 2013, maintenance technicians were tuning the A MS
emergency level controller following its replacement in accordance with PSEG
procedure HC.IC-LC.AF-00007, Moisture Separator Drain Tank Level Tuning.
Enclosure
27
During the tuning evolution, the A MS dump valve failed closed, causing a turbine trip
due to high A MS level and automatic reactor scram.
The moisture separators improve the quality of the steam from the high pressure turbine
exhaust, and minimize erosion of the low pressure turbines due to excessively moist
steam. The levels in the A and B MSs are maintained through a normal drain path
through three drain valves on each MS to the #5 feedwater heaters. The position of the
drain valves is controlled by the MS normal level controller. When the level in the MS
is above the normal drain control level, a high level emergency dump valve (one per MS)
directs flow from the MS to the condenser. The emergency level dump valve is normally
closed and is controlled by the MS emergency level controller.
PSEG procedure HC.IC-LC.AF-00007, Moisture Separator Drain Tank Level Tuning,
raises MS level into the emergency dump range to tune the emergency level controller
by manually closing the normal drain valves. This evolution was evaluated and
determined to be a high risk evolution in accordance with WC-AA-105, Work Activity
Risk Management. A risk management plan was developed for the high risk activity.
WC-AA-105 requires that the risk management plan be presented for approval by a risk
management challenge board prior to performance of the high risk activity.
This plan was initially reviewed by a risk management challenge board and was not
approved. An action from the risk management challenge board included ensuring that
during the tuning, one person is to be stationed at the normal level controller and one at
the emergency level controller. The risk management challenge board directed that both
people would need to be prepared to respond in case the MS drain tank level rises
during the tuning evolution. A second risk management challenge board was held to
review the risk management plan. The contingency action for stationing maintenance
technicians at each controller was not implemented.
The second challenge board failed to ensure that contingency actions were appropriate
for the activity being performed as specified by PSEG procedure WC-AA-105. A
heightened level of awareness (HLA) brief was performed prior to performance of the
high risk activity. Having a maintenance technician at the normal and emergency level
controllers was discussed. Contrary to the direction of the risk management challenge
board and the HLA brief, a maintenance technician was not stationed at the normal level
controller during the tuning of the emergency level controller. PSEGs corrective actions
included conducting performance management with the individuals involved with the
tuning evolution, and revising the moisture separator drain tank level tuning procedure to
require an individual at the normal and emergency controllers when performing
emergency level controller tuning.
Analysis. The inspectors determined that PSEGs failure to ensure that the contingency
actions were appropriate for the activity being performed prior to A MS emergency
level controller tuning was a performance deficiency that was within PSEGs ability to
foresee and correct, and should have been prevented. Specifically, a contingency action
specified by the risk management challenge board and the HLA brief prior to the high
risk tuning activity was not performed. As a result, the technicians were unable to
restore air to the drain valves in time to reduce the A MS level before the high level
caused a turbine trip and reactor scram.
Enclosure
28
This finding was more than minor because it was associated with the human
performance attribute of the Initiating Events cornerstone, and adversely affected the
cornerstone objective to limit the likelihood of events that upset plant stability and
challenge critical safety functions during shutdown as well as power operations. The
inspectors determined that this finding was of very low safety significance (Green) using
Exhibit 1 of NRC IMC 0609, Appendix A, The Significance Determination Process
(SDP) for Findings At-Power, dated June 19, 2012, because the finding did not cause
both a reactor trip and the loss of mitigation equipment relied upon to transition the plant
from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of
feed water). The inspectors determined that the finding had a cross-cutting aspect in the
Human Performance area associated with Work Management, because PSEG
personnel did not implement a process of planning, controlling, and executing work
activities such that nuclear safety is the overriding priority. Specifically, technicians were
only stationed at the emergency level controller during the tuning, when having
technicians at both controllers would have provided more time to recover from a high
level condition in the A MS, and may have prevented the turbine trip and subsequent
reactor scram on December 5, 2013. (H.5)
Enforcement. This finding was not a violation of NRC requirements because no violation
of regulatory requirements was identified. Since this finding does not involve a violation
and is of very low safety significance (Green), it is identified as a FIN. (FIN
05000354/2014003-04, Inadequate Implementation of Contingency Actions During
Moisture Separator Emergency Level Controller Tuning)
.6 (Closed) LER 05000354/2013-010-00, Loss of Both Main Control Room Chillers
a. Inspection Scope
On December 20, 2013, at 1:03 pm, while the B MCR chiller was out of service in
support of maintenance, the A MCR chiller was manually secured due to excessive
fluctuations in load. The TSAS (TS 3.7.2.2 Action a.2) for both MCR air conditioning
subsystems inoperable was entered. At 9:20 pm, the B control area ventilation train
and chiller were placed in service for post maintenance testing, returned to an operable
status, and the TS action statement was exited.
This condition is reportable under 10 CFR 50.73(a)(2)(v)(D) as an event or condition that
could have prevented the fulfillment of the safety function of structures or systems that
are needed to mitigate the consequences of an accident. The inspectors reviewed
PSEGs LER and LER revision, apparent cause evaluation (Order 70162284),
supporting documentation, station procedures, and interviewed several members of
station staff and management regarding the event. One finding was identified and is
discussed below. These LERs are closed.
b. Findings
Introduction. A Green self-revealing NCV of 10 CFR 50, Appendix B, Criterion III,
Design Control, was identified for PSEGs failure to effectively implement the DCP
process. Specifically, PSEGs DCP 4EC-3662 failed to reclassify the PC of the MCR
chiller PCV positioner from non-safety related (PC4) to safety related (PC1). Because of
the incorrectly assigned PC, PSEG did not track the shelf life of replacement positioner
diaphragms, which led to the failure of the A MCR positioner on December 20, 2013.
Enclosure
29
As a result, while the B MCR chiller was inoperable following planned maintenance, the
A MCR chiller had to be manually secured due to excessive fluctuations in load caused
by the failed positioner, and led to both MCR chillers being inoperable.
Description. The control room envelope (CRE) heating, ventilation and air conditioning
(HVAC) systems are designed to ensure habitability during any design basis radiological
accident. Redundant HVAC systems are provided to control the ambient conditions for
safety-related equipment to ensure operating temperature limits are not exceeded. The
A and B MCR chillers provide the accident function of maintaining the temperature of
the CRE for equipment performance and operator comfort.
On December 20, 2013, at 1:03 pm, while the B MCR chiller was out of service in
support of maintenance, the A MCR chiller was manually secured due to excessive
fluctuations in load. TS action statement 3.7.2.2.a.2 for both MCR chillers being
inoperable was entered. This condition was reportable per 10CFR50.72(b)(3)(v)(D), as
an event or condition that could have prevented the fulfillment of the safety function of
structures or systems that are needed to mitigate the consequences of an accident,
PSEG submitted an eight-hour event notification (#49671) for concurrent inoperability of
both MCR chillers. At 9:20 pm (~8 hours into the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS action statement), the B
MCR chiller was placed in service for post maintenance testing and returned to an
operable status, allowing PSEG to exit the TS. Throughout the time both chillers were
inoperable, the MCR temperature was maintained below the TS limit of 90 degrees
Fahrenheit.
PSEG conducted an equipment apparent cause evaluation (EQACE 70162284) and
determined the A MCR chiller excessive load fluctuations were the result of an
inoperable chiller condenser PCV. The positioner for the PCV, which provides cooling
water flow to the chiller condenser, failed due to a leak in the positioner's internal relay
assembly, which is made up of a series of diaphragms. This positioner had failed
previously due to a missing roller bearing and C clip, and was replaced at the end of
2011. The replaced positioner that failed on December 20, 2013, had only been
installed for 2 years. The damaged diaphragm in the positioners relay assembly
allowed an internal leakage path for the air, resulting in the failure of the positioner to
operate properly. This failure was determined to be age-related caused by a legacy
issue with the implementation of DCP 4EC-3662 in 1997. The chiller PCV has an active
safety function in the open position to provide cooling water flow to the MCR chiller. On
a loss of instrument air, the chiller PCV was originally designed to fail open, but this DCP
installed backup air bottles to supply the chiller PCV, preventing the PCV from failing
open so that the chiller would not trip on low evaporator refrigerant pressure. This
design change resulted in the PCV becoming self-modulating, changing the
classification of the PCV positioner from nonsafety-related to safety-related. PSEGs
evaluation of this DCP in the EQACE concluded that the DCP failed to identify that the
PC of the positioner for the PCV should have been changed from nonsafety-related to
safety-related and as a result, the PC was not changed. If the PC of the positioner had
been changed to PC1, a positioner that had been on the shelf for more than 20 years
would not have been installed into a safety-related system. But because the PC was not
changed, PSEG determined that the shelf life of the in-stock replacement positioners
was not tracked, leading to the installation of a positioner in 2011 that had been
manufactured 21 years before.
Enclosure
30
PSEGs determined that the MCR chiller PCV positioner failed to operate because of
internal relay leakage caused by damaged diaphragms. These diaphragms failed due to
the positioners age exceeding the vendor recommended lifetime of 4 years. PSEG has
entered this issue into the CAP as NOTF 20642546. As part of PSEGs corrective
actions the site has replaced the failed positioner and changed the purchase
classification for the chiller PCV positioners to safety-related (PC1).
Analysis. PSEGs failure to effectively implement the DCP process for DCP 4EC-3662
was a performance deficiency that was within the licensees ability to foresee and
correct, and should have been prevented. Specifically, because of the incorrectly
assigned PC, PSEG did not track the shelf life of replacement positioner diaphragms,
which led to the failure of the A MCR positioner on December 20, 2013. The inspectors
determined that the performance deficiency was more than minor because it is
associated with the design control attribute of the of the barrier integrity cornerstone, and
adversely affected the cornerstone objective of maintaining the radiological barrier
functionality of the control room Exhibit 3 of IMC 0609, Appendix A, The Significance
Determination Process (SDP) for Findings at Power, issued June 19, 2012, the
inspectors determined that this finding is of very low safety significance (Green) because
the performance deficiency represents a degradation of only the radiological barrier
function provided for the control room. Since the implementation of DCP 4EC-3662, the
DCP procedures have been enhanced to ensure the completion of a purchase class
evaluation of procured materials that are implemented in the DCP process.
The inspectors determined that there was no cross-cutting aspect associated with this
finding because the cause of the performance deficiency occurred more than three years
ago, and was not representative of current plant performance.
Enforcement. 10 CFR 50, Appendix B, Criterion III, Design Control, states, in part, that
measures shall be established to assure that applicable regulatory requirements and the
design basis for structures, systems, and components shall be correctly translated into
specifications, drawings, procedures, and instructions.
Contrary to this, PSEGs implementation of DCP 4EC-3662 in 1997, failed to reclassify
the PC of the MCR chiller PCV positioner from nonsafety-related to safety-related.
Because of the incorrectly assigned PC, PSEG did not track the shelf life of replacement
positioner diaphragms, which led to the failure of the A MCR positioner on
December 20, 2013. PSEGs corrective actions include replacement of the failed
positioner and changing the PC for the MCR PCV positioners to safety-related.
Because of the very low safety significance (Green) and because the issue was entered
into the CAP as notification 20642546, this violation is being treated as an NCV,
consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV
05000354/2014003-05, Inadequate Evaluation of a Main Control Room Chiller
Design Change)
4OA5 Other Activities
Temporary Instruction (TI) 2515/182, Phase II, Underground Piping and Tank Integrity
(1 sample)
Enclosure
31
a. Inspection Scope
The licensees buried piping and underground piping and tanks program was inspected
in accordance with paragraph 03.02.a of the TI. It was confirmed that activities which
correspond to completion dates specified in the program, which have passed since the
Phase 1 inspection was conducted, have been completed.
Additionally, the licensees buried piping and underground piping and tanks program was
inspected in accordance with paragraph 03.02.b of the TI and responses to specific
questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-
phase-2-insp-req-2011-11-16.pdf were submitted to the NRC headquarters staff.
b. Findings
No findings were identified.
4OA6 Meetings, Including Exit
On July 10, 2014, the inspectors presented the inspection results to Mr. Paul Davison,
Hope Creek Site 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.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by the
licensee and is a violation of NRC requirements which meets the criteria of the NRC
Enforcement Policy, for being dispositioned as a NCV:
In Modes 1, 2, and 3, Hope Creek TS 3.4.2.1, "Safety Relief Valves," requires that
13 of the 14 SRVs open within of +/- 3 percent of the specified code safety valve
function lift settings or else be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Mode 4 within the
next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Contrary to this requirement, on November 22, 2013, PSEG identified
that five of the fourteen SRVs were determined to have their as-found setpoints in
excess of the TS allowable tolerance, thus leaving nine operable SRVs. The pilot
assembly for each of the fourteen SRVs has been replaced with a fully tested spare
assembly. Additionally, LER 2013-007 stated PSEGs proposal to replace the SRVs
is being considered through the plant modification process. PSEG entered this issue
into their CAP as notification 20631351. The inoperability of the five SRVs did not
result in a loss of system safety function based on engineering analyses that showed
that postulated piping stresses would not exceed allowable limits. Therefore, this
finding is of very low (Green) safety significance based on an SDP issue screening,
because the SRVs would have functioned to prevent a reactor vessel over-
pressurization. The closure of the LER associated with this event was documented
in Section 4OA3.
ATTACHMENT: SUPPLEMENTARY INFORMATION
Enclosure
A-1
SUPPLEMENTARY INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
P. Davison, Site Vice President
E. Carr, Plant Manager
P. Bellard, Program Engineering
S. Bier, EOP Coordinator
M. Biggs, Hope Creek Maintenance Rule Coordinator
M. Cardile, Fire Protection Supervisor
J. Carlin, Fire Protection Superintendent
S. Connelly, System Engineer
A. DiEgidio, Chemistry Technician
T. Headman, Emergency Preparedness Technical Specialist
W. Hickey, Work Week Manager
C. Johnson, Senior Program Engineer
E. Martin, Senior Program Engineer
J. Master, Chemistry Technician
M. Meltzer, Chemistry
T. Morin, Regulatory Assurance Engineer
M. Reeser, System Engineer
M. Rooney, System Engineer
R. Smith, System Engineer
K. Timko, System Engineer
A. Tramontana, Program Engineering Manager
M. Tudisco, Nuclear Maintenance Supervisor
K. Wichman, System Engineer
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Opened/Closed
05000354/2014003-01 NCV Inadequate Procedural Guidance for Responding
to an Internal Flooding Event in the HPCI and
RCIC Rooms (Section 1R06)05000354/2014003-02 FIN Failure to Evaluate an Identified Issue with the
Moisture Separator Dump Valve Performance
(Section 1R12)05000354/2014003-03 NCV Failure to Follow Procedure Resulting in the Loss
of a Vital 4kV Bus (Section 1R13)05000354/2014003-04 FIN Inadequate Implementation of Contingency
Actions During Moisture Separator Emergency
Level Controller Tuning (Section 4OA3)
Attachment
A-2
05000354/2014003-05 NCV Inadequate Evaluation of a Main Control Room
Chiller Design Change (Section 4OA3)
Closed
05000354/2013-007-00 LER As-Found Values for Safety Relief Valve Lift Set
Points Exceed Technical Specification Allowable
Limit (Section 4OA3)
05000354/2013-008-01 LER Automatic Actuation of the Reactor Protection
System Due to a Main Turbine Trip (Section
4OA3)
05000354/2013-009-01 LER Automatic Actuation of the Reactor Protection
System Due to a Main Turbine Trip (Section
4OA3)
05000354/2013-010-00 LER Loss of Both Main Control Room Chillers (Section
4OA3)
LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
Procedures
ER-HC-310-1009, HCGS - Maintenance Rule Scoping, Revision 10
HC.MD-GP.ZZ-0037, Plant Bulkhead Doors Overhaul, Revision 5
HC.MD-PM.ZZ-0007, Missile Resistant and Watertight Doors Preventative Maintenance,
Revision 9
HC.OP-AB.MISC-0001, Acts of Nature, Revision 23
HC.OP-DL.ZZ-0014, Monday Shift Routine Log, Revision 34
HC.OP-GP.ZZ-0003, Station Preparations for Winter Conditions, Revision 29
OP-AA-108-111-1001, Severe Weather and Natural Disaster Guidelines, Revision 9
WC-AA-107, Seasonal Readiness, Revision 13
Other Documents
2013 Summer Readiness Hope Creek Critique
2014 Hope Creek Summer Readiness Affirmation Certification Letter, dated May 1, 2014
Notifications (*NRC-identified)
20546153 20562816 20610276 20612823 20613802 20615133
20649147 20650908 20650999 20652771* 20652918* 20654490
20654491 20654493 20654495 20654496
Maintenance Orders/Work Orders
30236406 60092591 60104126 60112815 60112948 60114177
60115861 70159564 80107747 80110867
Attachment
A-3
Drawings
A-0203-0, General Plant Floor Plan Level 3 - Elevation 102, Revision 19
Section 1R04: Equipment Alignment
Procedures
HC.OP-ST.BD-0001, RCIC Piping and Flow Path Verification - Monthly, Revision 14
HC.OP-ST.EA-0001, Service Water Flow Path Verification - Monthly, Revision 11
OP-AA-108-116, Protected Equipment Program, Revision 9
OP-HC-108-115-1001, Operability Assessment and Equipment Control Program, Revision 27
Notifications (*NRC-identified)
20529358 20529359 20529360 20529362 20636088 20636089
20647011 20648223 20649406* 20649407* 20649408* 20649409*
Maintenance Orders/Work Orders
30255253 50165993 70127188 70129996
Drawings
E-0485-0, Electrical Schematic Auxiliary Building - Diesel Area Switchgear Room Coolers and
Air Dampers, Sht. 3, Revision 8
M-10-1, Sheet 1, Service Water, Revision 54
M-10-1, Sheet 2, Service Water, Revision 43
M-49-1, Reactor Core Isolation Cooling, Revision 30
M-50-1, RCIC Pump Turbine, Revision 29
Miscellaneous
HCGS PRA Risk Evaluation Form for Work Week #1418, Revision 3, dated May 2, 2013
MP 192355
NRC IN 96-06, Design and Testing Deficiencies of Tornado Dampers at Nuclear Power Plants
OE 33769
PM 30255253
Protected Equipment Log for HPCI Sight Glass Repair, dated May 2, 2014
Section 1R05: Fire Protection
Procedures
FP-AA-014, Fire Protection Training Program, Revision 1
FP-AA-015, Compensatory Measure Firewatch Program, Revision 5
FP-AA-028-1001, Emergency Response Safety and Risk Management Plan, Revision 0
FP-HC-004, Actions for Inoperable Fire Protection - Hope Creek Station, Revision 1
FRH-II-332, Service & Radwaste Area, Elevation: 102-0, Revision 4
FRH-II-412, Hope Creek Pre-Fire Plan, RCIC Pump and Turbine Room, RHR Pump and Heat
Exchanger Rooms, and Electrical Equipment Room, Elevations 54, Revision 3
FRH-II-415, Hope Creek Pre-Fire Plan, Dry Well Pad Torus Area, Elevations: 54-0 &77-0,
Revision 4
FRH-II-522, Hope Creek Pre-Fire Plan, Cable Spreading Room, Elevation: 77-0, Revision 6
FRH-II-532, Hope Creek Pre-Fire Plan, Lower Control Equipment Room, Elevation: 102-0,
Revision 6
Attachment
A-4
FRH-II-542, Hope Creek Pre-Fire Plan, Control Equipment Mezzanine, Elevations: 117-6 &
124-0, Revision 6
FRH-II-551, Hope Creek Pre-Fire Plan, Battery Rooms & Cable Chases, Elevations: 146-0 &
150-0, Revision 6
HC.OP-IS.BD-0001, Reactor Core Isolation Cooling Pump - OP203 - Inservice Test, Rev 58
SH.FP-EO.ZZ-0002, Fire Department Fire Response, Revision 3
Notifications (*NRC identified)
20632422 20633801 20639488 20642920 20644734 20644822
20646267 20646330 20646361 20647111 20647263* 20647351*
20651472
Maintenance Orders/Work Orders
0158901 50165299 70143862 70161457
Drawings
M-50-1, P&ID RCIC Pump Turbine, Revision 29
Miscellaneous
Fire Protection Impairment Permit 11760, dated April 16, 2014
Section 1R06: Flood Protection Measures
Procedures
EP-HC-111-130, HC EAL Wall Chart - All Conditions, Revision 1
HC.OP-AR.ZZ-0004, Overhead Annunciator Window Box A6, Revision 18
HC.OP-AR.ZZ-0006, Overhead Annunciator Window Box B1, Revision 25
HC.OP-AR.ZZ-0022, CRIDS Computer Points Book 3 D2880 Thru D3257, Revision 19
HC.OP-EO.ZZ-0103/4, Reactor Building and Radioactive Release Control, Revision 9
HC.OP-EO.ZZ-0103/4-CONV, Hope Creek Emergency Operating Procedure Conversion
Document, Revision 9
HC.OP-EO.ZZ-0103/4-FC, Reactor Building and Radioactive Release Control Flow Chart,
Revision 9
Notifications (*NRC identified)
20643688* 20643694* 20643696* 20643885* 20643886* 20643887*
20646334* 20646335* 20653586* 20656703*
Drawings
A-4641-1, Reactor Building Unit 1 Floor Plan at El. 54-0, Revision 6
J-25-0, Sheet 5, Logic Diagram Plant Leak Detection, Revision 6
M-25-1, Sheet 1, Plant Leak Detection, Revision 8
M-97-1, Sheet 2, Building and Equipment Drain Reactor Building, Revision 18
Other Documents
Calculation Number 11-0092, Reactor Building Flooding - Elevation 54 and 77, Revision 5
Calculation Number BC-0031, ECCS Pump Rooms Flood Level Alarm Set Point, Revision 1
HC-PRA-012, Internal Flood Evaluation Summary and Notebook, Revision 2
HC-PRA-017, Internal Flood Walkdown Notebook, Revision 0
Attachment
A-5
Section 1R11: Licensed Operator Requalification Program
Procedures
CY-AB-120-340, Offgas Chemistry, Revision 8
HC.OP-AB.IC-0001, Control Rod, Revision 16
HC.OP-FT.AC-0002, Main Turbine Functional Test Monthly, Revision 31
HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test - Quarterly,
Revision 13
HC.OP-ST.AC-0002, Turbine Valve Testing - Quarterly, Revision 49
HU-AA-1211, Pre-Job Briefings, Revision 11
NF-AA-400-1000, Fuel Integrity Monitoring, Revision 4
NF-AA-400-1700, BWR Fuel Reliability Indicator (FRI) Calculation and Transmittal, Revision 1
NF-AA-430, Failed Fuel Action Plan, Revision 8
OP-AA-101-111-1004, Operations Standards, Revision 4
OP-AA-108-111, Attachment 1, Adverse Condition Monitoring and Contingency Plan, Revision 7
OP-AA-300, Reactivity Management, Revision 6
OP-AB-300-1001, BWR Control Rod Movement Requirements, Revision 6
OP-AB-300-1003, BWR Reactivity Maneuver Guidance, Revision 11
Notifications
20543906 20566308 20644437
Maintenance Orders/Work Orders
50163804 70140638 80110856
Other Documents
HC 14-01, OTDM for Turbine Overspeed Protection System Operability Test - Quarterly,
February 11, 2014
HC 14-008, ACM for Fuel Reliability Parameters used to Monitor Fuel Defect indicate potential
fuel failure, March 25, 2014, Revision 0
Hope Creek Long Term Trends - 2014 for Failed Fuel Monitoring (NOTF 20644437)
Hope Creek Failed Fuel Monitoring Team Meeting on March 15, 2014
REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0
Miscellaneous
Scenario Guide (SG)-644, Reactor Recirc Pump Trip / RWCU Leak / Loss of Main Condenser
Vacuum / ATWS dated April 24, 2014
Section 1R12: Maintenance Effectiveness
Procedures
ER-AA-10, Equipment Reliability Process Description, Revision 1
ER-AA-310, Implementation of the Maintenance Rule, Revision 11
ER-AA-310-1001, Maintenance Rule - Scoping, Revision 6
ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Revision 10
ER-AA-310-1005, Maintenance Rule - Dispositioning Between (a)(1) and (a)(2), Revision 9
ER-HC-310-1009, Maintenance Rule System Function and Risk Significant Guide, Revision 10
ER-SA-310-1009, Salem Generating Station - Maintenance Rule Scoping, Revision 4
HC.DE-PS.ZZ-0041, Hope Creek Station Blackout Program, Revision 3
Attachment
A-6
HC.IC-CC.SK-0002, RCIC - Division 4 Steam Leak Detection Temperature Monitor H1SK-
1SKXR-11503, Revision 14
HC.IC-DC.SK-0001, NUMAC Leak Detection Setup and Trip Selection, Revision 11
HC.OP-AB.ZZ-0135, Station Blackout // Loss of Offsite Power // Diesel Generator Malfunction,
Revision 39
LS-AA-125, Corrective Action Program, Revision 17
MA-AA-716-004, Conduct of Troubleshooting, Revision 12
MA-AA-716-012, Post Maintenance Testing, Revision 19
MA-AA-716-210-1005, Predefine Change Process, Revision 3
S1.OP-AB.LOOP-0001, (Salem) Loss of Off-site Power, Revision 29
WC-AA-111, Predefine Process, Revision 8
Notifications
20335737 20413574 20447050 20502118 20570839 20619184
20623712 20638460 20640526 20645207 20651951
Orders
60113250 70073704 70105948 70121525 70124871 70157974
70161698 80110856
Miscellaneous
HC 10-03, License Amendment Request for Extending the Allowed Outage Time for the A and
B EDGs from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days
HC 13-015, OTDM for Continued Operation of the Moisture Separator without a Root Cause for
the Dump Valve Failing to Control Level, dated December 6, 2013
NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear
Power Plants, Revision 4
NRC Correspondence, HCGS - Issuance of Amendment Re: Emergency Diesel Generators A
and B Allowed Outage Time Extension, dated March 25, 2011
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
HC.CH-SA.HA-0002, Sampling Offgas System from 00-C-963 Panel, Revision 8
HC.OP-AB.RPV-0001, Reactor Power, Revision 13
HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test - Quarterly,
Revision 13
HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57
HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98
HC.OP-SO.PB-0001, 4.16KV System Operation, Revision 29
HC.OP-ST.PB-0002, AC Power Supply Transfer Functional Test - 18 Months, Revision 11
HC.OP-ST.ZZ-0001, Power Distribution Lineup - Weekly, Revision 36
MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and
Practices, Revision 7 and 14
NC.CH-RC.ZZ-2525, Gamma Spectroscopy Analysis Using CAS, Revision 4
NF-AB-431, Power Suppression Testing, Revision 6
WC-AA-101, On-Line Work Management Process, Revision 22
WC-AA-105, Work Activity Risk Management, Revision 2
Attachment
A-7
Notifications (*NRC identified)
20465881 20521256 20585982 20593568 20600597 20627730
20632023 20634061 20637967 20638221 20639498 20639519
20644437 20645095 20645435 20645701* 20645705 20650898
20650904 20651102 20651204 20651430 20651432 20651876
20653142
Maintenance Orders/Work Orders
30098613 30098617 30243196 30265556 60061175 60114688
60117312 70046681 70072347 70097158 70110518 70142932
70155514 70162013
Miscellaneous
DCP 4-HC-0170
HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, dated May 17, 2014
HCGS Operations Narrative Logs, May 14-15, 2014
HCGS PRA Risk Evaluation Form for June 8, 2014, through June 14, 2014, Revision 0
Protected Equipment Log -F FRVS Recirc Fan, dated June 8, 2014
HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3
NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1
REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0
Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated
November 15, 2013
Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP
Speed Control Loop, dated May 14, 2014
WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1
Section 1R15: Operability Determinations and Functionality Assessments
CC-AA-309-101, Engineering Technical Evaluations, Revision 10
ER-AA-2006, Lost Parts Evaluation, Revision 8
HC.CH-CA.ZZ-0026, Boron by Mannitol Titration, Revision 18
HC.OP-AB.RPV-0001, Reactor Power, Revision 13
HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57
HC.OP-IS.BH-0004, Standby Liquid Control Pump - BP208 - Inservice Test, Revision 12
HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98
HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 70
HC.OP-SO.PB-0001, 4.16KV System Operation, Revision 29
HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test - Monthly,
Revision 76
HC.OP-ST.PB-0002, AC Power Supply Transfer Functional Test - 18 Months, Revision 11
HC.OP-ST.ZZ-0001, Power Distribution Lineup - Weekly, Revision 36
HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party
Review and Post-Job Brief, Revision 8
MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and
Practices, Revision 7 and 14
WC-AA-101, On-Line Work Management Process, Revision 22
Attachment
A-8
Notifications (*NRC identified)
20221500 20439888 20442565 20442566 20465881 20521256
20585982 20593568 20600597 20616574 20627730 20632023
20634061 20637967 20638221 20639498 20639519 20640696
20643229 20643322* 20644637 20645519 20645994 20647199*
20650611* 20650701* 20650788* 20650831* 20650856* 20650858*
20650898 20650904 20651102 20651204 20651430 20651432
20651876 20652187 20652199 20653142 20653635*
Drawings
M-52-1, Core Spray, Revision 31
M-52-1, Sheet 1, Residual Heat Removal, Revision 45
M-52-1, Sheet 2, Residual Heat Removal, Revision 40
Maintenance Orders/Work Orders
30098613 30098617 30243196 50165850 60061175 60087495
60087534 60087538 60087539 60087540 60087541 60089905
60114688 60117312 70046681 70072347 70097158 70110518
70142932 70149472 70155514 70157453 70162013 70163760
70164628 80079629 80079863 80108395 80111752 80111754
Miscellaneous
10855-D3.33, Design, Installation and Test Specification for Standby Liquid Control System for
the Hope Creek Generating Station, Revision 5
22A7641, Design Specifications for SLC System, Revision 1
ASTM E29-13, Standard Practice for Using Significant Digits in Test Data to Determine
Conformance with Specifications
C-0001, Wall Thickness Calculation for Piping, Revision 9
Calculation 1SC-BH-0001, SLC System Tank 10T-204 Level, Revision 0
DCP 4-HC-0170
DCP 4HM-0136, Change Standby Liquid Control Tank Sodium Pentaborate Concentration from
13.4 to 14.0 Weight Percent, dated December 17, 1987
HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, May 17, 2014
HCGS Operations Narrative Logs, May 14-15, 2014
HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3
LD-042-MASTERPACT-1, Masterpact Issues, Revision 1
NLR-N87131, Request for Amendment Facility Operating License NPF-57 Hope Creek
Generating Station Docket No. 50-354, dated July 14, 1987
NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1
Part 9900: Technical Guidance, Standard Technical Specifications Section 3.0 Acceptable
Measurement Tolerances for Technical Specification Limits, dated October 1, 1978
PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,
Revision 25
Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated November
15, 2013
Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP
Speed Control Loop, dated May 14, 2014
WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1
Attachment
A-9
Section 1R18: Plant Modifications
Procedures
CC-AA-102, Design Input and Configuration Change Impact Screening, Revision 23
CC-AA-103, Configuration Change Control for Permanent Physical Plant Changes, Revision 15
CC-AA-112, Temporary Configuration Changes, Revision 13
CC-AA-112-1001, Temporary Configuration Change Implementation T&RM, Revision 2
OP-AA-115-101, Operator Aid Postings, Revision 3
Notifications
20439888 20639161 20640696 20651205 20652187
Maintenance Orders/Work Orders
60115429 70163760 80107203 80111298 80111754
Drawings
M-08-0, Sheet 1, Condensate & Refueling Water Storage & Transfer, Revision 34
Miscellaneous
DCP 80111754, Masterpact Breaker Add Aux Contact with Close Coil, Revision 1
H-1-ZZ-EGS-0043, Hope Creek Generating Station GE AKR Circuit Breaker Replacement
Project
LD-042-MASTERPACT-1, Revision 1
OPEVAL 14-002, Masterpact Breaker Model NW with Locked in Close Signal, Revision 3
Temporary Configuration Change Package Tracking Log, dated June 10, 2014
Section 1R19: Post-Maintenance Testing
Procedures
CC-AA-309-101, Engineering Technical Evaluations, Revision 10
HC.IC-CC.SK-0002, RCIC - Division 4 Steam Leak Detection Temperature Monitor H1SK-
1SKXR-11503, Revision 14
HC.IC-DC.SK-0001, NUMAC Leak Detection Setup and Trip Selection, Revision 11
HC.IC-DC.ZZ-0011, Device/Equipment Calibration Bailey, Characterizable Pneumatic
Positioner, Type AP2, Revision 5
HC.OP-AB.COMP-0001, Instrument and/or Service Air, Revision 5
HC.OP-AB.RPV-0001, Reactor Power, Revision 13
HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57
HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - OP204 and OP217 - Inservice Test,
Revision 62
HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98
HC.OP-ST.BC-0005, LPCI Subsystem B ECCS Time Response Functional Test - 18 Months,
Revision 16
HC.OP-ST.ZZ-0001, Power Distribution Lineup - Weekly, Revision 36
HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party
Review and Post-Job Brief, Revision 8
MA-AA-716-012, Post Maintenance Testing, Revision 19
MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and
Practices, Revision 7 and 14
SM-AA-410, Control of Purchased Material, Equipment and Services Program, Revision 6
WC-AA-101, On-Line Work Management Process, Revision 22
Attachment
A-10
Notifications (*NRC identified)
20454035 20465881 20521256 20619184 20623712 20623802
20629385 20632023 20642546 20642950 20647111 20650904
20651102 20651430 20651872 20651951 20652010 20652012
20652232 20652238 20652321 20652339 20652702 20653142
20653572* 20653872*
Maintenance Orders/Work Orders
30098613 30098617 30240742 30269527 50163142 60113238
60113250 60116090 60117312 70125746 70155514 70157974
70163994 70166194
Drawings
PN11-E11-1040-0383, Sheet 3, Residual Heat Removal System, Revision 15
PN11-E11-1040-0383, Sheet 12, Residual Heat Removal System, Revision 18
PN11-E11-1040-0383, Sheet 13, Residual Heat Removal System, Revision 10
PN11-E11-1040-0383, Sheet 22, Residual Heat Removal System, Revision 17
Miscellaneous
HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, dated May 17, 2014
HCGS Operations Narrative Logs, May 14-15, 2014
HCGS PRA Risk Evaluation Form for April 20, 2014 through April 26, 2014
HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3
NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1
Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated
November 15, 2013
Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP
Speed Control Loop, dated May 14, 2014
WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1
Section 1R22: Surveillance Testing
Procedures
CC-AA-309-101, Engineering Technical Evaluations, Revision 10
ER-AA-2006, Lost Parts Evaluation, Revision 8
FP-HC-004, Actions for Inoperable Fire Protection - Hope Creek Station, Revision 1
HC.FP-ST.KC-0009, Diesel Driven Fire Pump Operability Test, Revision 20
HC.IC-CC.SK-0016, Radiation Monitoring - Channel D Monitor H1SK-1SKLY-4930 Drywell
Leak Detection Sump Monitoring System (DLD-SMS), Revision 22
HC.IC-GP.ZZ-0004, Thermocouples (T/C) and Resistance Temperature Detectors (RTD),
Revision 8
HC.MD-ST.PB-0003, Class 1E 4.16 kV Feeder Degraded Voltage Monthly Instrumentation
Channel Functional Test, Revision 26
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 139
HC.OP-FT.AC-0002, Main Turbine Functional Test Monthly, Revision 31
HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test - Quarterly,
Revision 13
HC.OP-IS.BC-0002, CP202, C Residual Heat Removal Pump In-Service Test, Revision 43
HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - 0P204 and 0P217 - Inservice Test,
Revision 62
Attachment
A-11
HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 70
HC.OP-ST.AC-0002, Turbine Valve Testing - Quarterly, Revision 49
HC.OP-ST.KJ-0001, Emergency Diesel Generator 1AG400 Operability Test - Monthly,
Revision 76
HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test - Monthly,
Revision 78
HC.OP-ST.SK-0001, Alternate RCS Leakage Determination, Revision 9
HU-AA-1211, Pre-Job Briefings, Revision 11
HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party
Review and Post-Job Brief, Revision 8
OP-AA-101-111-1004, Operations Standards, Revision 4
OP-AA-108-101, Control of Equipment and System Status, Revision 7
OP-AA-300, Reactivity Management, Revision 6
Notifications
20504658 20629522 20630428 20630429 20640032 20645519
20645994 20646319 20648114 20648751 20649201 20649292
20649425 20649905 20649906 20654936
Maintenance Orders/Work Orders
30199753 50163804 50164408 50164695 50165664 50165690
50165691 50165850 50166624 50167441 50169340 60026593
60058122 60097901 60107882 70008407 70023178 70097767
70122058 70127960 70139509 70145982 80111752
Calculations
SC-SK-0118, Drywell Leak Detection SMS (Floor Drain Unidentified Leakage), Revision 2
Miscellaneous
HC 14-01, OTDM for Turbine Overspeed Protection System Operability Test - Quarterly, dated
February 11, 2014
HCGS PRA Risk Evaluation Form for April 6, 2014, through April 12, 2014
PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,
Revision 25
REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0
Section 1EP6: Drill Evaluation
Procedures
EP-AA-122, Drills and Exercises, Revision 3
EP-AA-122-1001, Drill and Exercise Scheduling, Development and Conduct, Revision 3
EP-AA-125-1002, NRC Drill and Exercise Performance (DEP) Indicator Guidance, Revision 3
EP-HC-111-121, Fission Product Barrier Table, Revision 1
EP-HC-111-230, Use of Fission Product Barrier Table, Revision 0
NC.EP-EP.ZZ-0102, Emergency Coordinator Response, Revision 18
NC.EP-EP.ZZ-0404, Protective Action Recommendations (PARS) Upgrades, Revision 4
Notifications
20654844
Attachment
A-12
Miscellaneous
DEP Observation Checklist for FAD-HC14-02, dated June 24, 2014
Section 4OA1: Performance Indicator Verification
Procedures
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 136
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 137
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 138
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 139
HC.RA-IS.ZZ-0010, Containment Isolation Valve Type C Leak Rate Test, Revision 15
LS-AA-2090, Monthly Data Elements for NRC Reactor Coolant System Activity, Revision 5
LS-AA-2100, Monthly Data Elements for NRC Reactor Coolant System Leakage, Revision 6
LS-HC-1000-1001, Hope Creek Generating Station Surveillance Frequency Control Program
List of Surveillance Frequencies, Revision 4
NC.CH-RC.ZZ-2525, Gamma Spectroscopy Analysis Using CAS, Revision 4
NC.CH-SA.RC-0002, Operation of the Reactor Building/RHR Sample Stations, Revision 18
Calculations
SC-SK-0119, Drywell Leak Detection SMS - Equipment Drain Sump, Revision 1
Notifications
20650305
Maintenance Orders/Work Orders
50137021 50149686 50162608
Miscellaneous
Daily Dose Equivalent Iodine-131 Sample Data
Daily Surveillance Log Data
Monthly Data Elements for NRC Reactor Coolant System Leakage Data Sheets
Section 4OA2: Problem Identification and Resolution
Procedures
ER-AA-2003, System Performance Monitoring and Analysis, Revision 9
ER-AA-3002, Component Cross-System Monitoring & Component Health Reporting, Revision 3
LS-AA-125, Corrective Action Program, Revision 17
LS-AA-125-1006, Performance Improvement Integrated Matrix (PIIM), Revision 5
LS-AA-1006, NRC Cross-Cutting Analysis and Trending, Revision 2
Notifications (*NRC identified)
20615843 20619913 20632801 20632802 20632361 20632641
20632746 20632747 20632748 20632749 20633058 20633338
20633339 20634028 20635871 20636138 20638889 20639772
20642767 20644539
Orders
70144876 70158815 70161953 70162269 80109029 80110809
80110866
Attachment
A-13
Miscellaneous
Hope Creek Engineering PIIM Report 1st Cycle 2013 Presentation, dated 8/31/13
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
Procedures
CC-AA-102, Design Input and Configuration Change Impact Screening, Revision 23
CC-AA-103, Configuration Change Control for Permanent Physical Plant Changes, Revision 15
ER-HC-310-1009, Maintenance Rule System Function and Risk Significant Guide, Revision 10
HC.IC-DC.ZZ-0140, Device/Equipment Cal. Masoneilan Pressure Temperature Controller,
Revision 4
HC.IC-LC.AF-0007, Moisture Separator Drain Tank Level Tuning, Revision 2
HC.OP-AB.RPV-0001, Reactor Power, Revision 13
HC.OP-AR.ZZ-0008, Overhead Annunciator Window Box C1, Revision 45
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 140
HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98
HC.OP-SO.GJ-0001, A(B) K400 Control Area Chilled Water System Operation, Revision 60
HU-AA-1211, Pre-Job Briefings, Revision 11
LS-AA-125-1003, Attachment 2, Equipment Apparent Cause Evaluation Guide, Revision 13DCP
MA-AA-716-004, Conduct of Troubleshooting, Revision 12
SM-AA-300, Procurement Engineering Support Activities, Revision 7
WC-AA-105, Work Activity Risk Management, Revision 2
Notifications (*NRC identified)
20454035 20521256 20528822 20529153 20567269 20570629
20630857 20631351 20631820 20631940 20632542 20638799
20640526 20642546 20642767 20643301 20644017 20645207
20647829 20650346* 20650904 20651102 20651876 20652180
20652182 20652183 20652184 20652185 20652186 20652188
20653024 20653142
Maintenance Orders/Work Orders
60114285 60114286 70041898 70110518 70115711 70119769
70128407 70129670 70140751 70142556 70159686 70161353
70161698 70162284
Miscellaneous
10855-d3.33, Design, Installation and Test Specification for Standby Liquid Control System for
the Hope Creek Generating Station, Revision 5
22A7641, Design Specifications for SLC System, Revision 1
ASTM E29-13, Standard Practice for Using Significant Digits in Test Data to Determine
Conformance with Specifications
Calculation 1SC-BH-0001, SLC System Tank 10T-204 Level, Revision 0
DCP 4-HC-0170
DCP 4HM-0136, Change Standby Liquid Control Tank Sodium Pentaborate Concentration from
13.4 to 14.0 Weight Percent, December 17, 1987
HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, dated May 17, 2014
HCGS Operations Narrative Logs, May 14-15, 2014
HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3
Attachment
A-14
LER 2013-009-00, Automatic Actuation of the Reactor Protection System Due to a Main Turbine
Trip
LER 2013-009-01, Automatic Actuation of the Reactor Protection System Due to a Main Turbine
Trip
NLR-N87131, Request for Amendment Facility Operating License NPF-57 Hope Creek
Generating Station Docket No. 50-354, dated July 14, 1987
NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1
Part 9900: Technical Guidance, Standard Technical Specifications Section 3.0 Acceptable
Measurement Tolerances for Technical Specification Limits, October 1, 1978
PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,
Revision 25
Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated
November 15, 2013
Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP
Speed Control Loop, dated May 14, 2014
WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1
Section 4OA5: Other Activities
Condition Reports
20650822 20650823 20652896
Procedures
ER-AA-5400, Underground Piping Program Guide, Revision 4
ER-AA-5400-1002, Underground Piping Examination Guide, Revision 3
SA-AA-117, Industrial Safety, Excavating Trenching, and Shoring, Revision 13
Miscellaneous
Cathodic Protection System Health Report for Hope Creek, Q1-2014
Cathodic Protection System Health Report for Salem U1, Q2-2014
Hope Creek Underground Piping Inspection Plan, Revision 3
LR-ISG-2011-03, Aging Management Program XI.M41, "Buried and Underground Piping and
Tanks"
NACE SP0169-2007, Control of External Corrosion on Underground or Submerged
Metallic Piping Systems, Revision 0
NEI-09-14, Guideline for the Management of Underground Piping and Tank Integrity
Location Sketch for Cathodic Protection of Salem U1 and U2 Structures, Revision 3
Program Health Report for the Salem Plant Underground Piping Program, P1-2014
Program Health Report for the Hope Creek Plant Underground Piping Program, P1-2014
Salem Underground Piping Inspection Plan, Revision 3
Underground Piping Inspection and Evaluation Report for Hope Creek line 0-DB-003, Liquid
RadWaste Discharge, dated February 22,2013
Underground Piping Inspection and Evaluation Report for Salem line SC-LW-0001-12-01, liquid
waste, Steam Generator Blowdown, dated September 11, 2012
Underground Piping Inspection and Evaluation Report for Salem lines S1-SG-1031-10 and S2-
SG-1111-10, dated September 17-20, 2012
UT report on Hope Creek component HODB-0-DB-V013, dated June 20, 2013
Attachment
A-15
LIST OF ACRONYMS
10 CFR Title 10 of The Code of Federal Regulations
ADAMS Agencywide Documents Access and Management System
CAP corrective action program
CCE common cause evaluation
CFR The Code of Federal Regulations
DCP design change package
EDG emergency diesel generator
EN event notification
EQACE equipment apparent cause evaluation
ER Environmental Report
HCGS Hope Creek Generating Station
HLA heightened level of awareness
HPCI high pressure coolant injection
HVAC heating, ventilation and air conditioning
IMC Inspection Manual Chapter
kV kilovolt
LER licensee event report
LM logic module
MCR main control room
MS moisture separator
NACE National Association of Corrosion Engineers
NCV non-cited violation
NEI Nuclear Energy Institute
NOTF notification
NRC Nuclear Regulatory Commission
NRR Nuclear Reactor Regulation
PARS Publicly Available Records
PC purchase classification
PCV pressure control valve
PI performance indicator
PIIM performance improvement integrated matrix
PSEG Public Service Enterprise Group Nuclear, LLC
PST power suppression testing
RCIC reactor core isolation cooling
RG Regulatory Guide
RRP reactor recirculation pump
RTP rated thermal power
SACS safety auxiliaries cooling system
SDP Significance Determination Process
SSC structure, system, or component
SSW station service water
Attachment
A-16
TCCP temporary configuration control package
TI Temporary Instruction
TS technical specifications
TSAS technical specification action statement
U1 Unit 1
U2 Unit 2
UFSAR Updated Final Safety Analysis Report
UT ultrasonic testing
V volt
WO work order
Attachment