ML15329A157
| ML15329A157 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 11/25/2015 |
| From: | Paul Krohn Engineering Region 1 Branch 2 |
| To: | Braun R Public Service Enterprise Group |
| References | |
| IR 2015007 | |
| Download: ML15329A157 (42) | |
See also: IR 05000354/2015007
Text
R. Braun
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION I
2100 RENAISSANCE BLVD., SUITE 100
KING OF PRUSSIA, PA 19406-2713
November 25, 2015
Mr. Robert Braun
President and Chief Nuclear Officer
P. O. Box 236
Hancocks Bridge, NJ 08038
SUBJECT:
HOPE CREEK GENERATING STATION - COMPONENT DESIGN BASES
INSPECTION REPORT 05000354/2015007
Dear Mr. Braun:
On October 23, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection
at the Hope Creek Generating Station. The enclosed inspection report documents the
inspection results, which were discussed on October 23, 2015, with Mr. Eric Carr, Plant
Manager, 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.
In conducting the inspection, the team examined the adequacy of selected components to
mitigate postulated transients, initiating events, and design basis accidents. The inspection
involved field walkdowns, examination of selected procedures, calculations and records, and
interviews with station personnel.
This report documents two NRC-identified findings that were of very low safety significance
(Green). These findings were determined to involve violations of NRC requirements. However,
because of the very low safety significance of the violations and because they were entered into
your corrective action program, the NRC is treating these findings as non-cited violations
(NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest any NCV
in this report, you should provide a response within 30 days of the date of this inspection report,
with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document
Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator,
Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,
Washington, D.C. 20555-0001; and the NRC Senior Resident Inspector at Hope Creek. In
addition, if you disagree with the cross-cutting aspect assigned to any finding 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 Senior Resident
Inspector at Hope Creek.
R. Braun
-2-
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) Part 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 the public inspection in the NRC Public Docket Room or from the
Publicly Available Record System (PARS) component of NRCs document system, Agencywide
Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC
Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Paul G. Krohn, Chief
Engineering Branch 2
Division of Reactor Safety
Docket No.
50-354
License No. NPF-57
Enclosure:
Inspection Report 05000254/2015007
w/Attachment: Supplementary Information
cc w/encl: Distribution via ListServ
SUNSI Review
Non-Sensitive
Sensitive
Publicly Available
Non-Publicly Available
OFFICE
RI/DRS
RI/DRS
RI/DRP
RI/DRS
NAME
JSchoppy
WCook
FBower
PKrohn
DATE
11/8/15
11/9/15
11/12/15
11/25/15
i
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No:
50-354
License No:
Report No:
Licensee:
Public Service Enterprise Group (PSEG) Nuclear LLC
Facility:
Hope Creek Generating Station (HCGS)
Location:
P.O. Box 236
Hancocks Bridge, NJ 08038
Inspection Period:
September 21 through October 23, 2015
Inspectors:
J. Schoppy, Senior Reactor Inspector, Team Leader
Division of Reactor Safety (DRS)
J. Brand, Reactor Inspector, DRS
J. Kulp, Senior Reactor Inspector, DRS
S. Makor, Reactor Inspector, RIV/DRS
S. Kobylarz, NRC Electrical Contractor
M. Yeminy, NRC Mechanical Contractor
Approved By:
Paul G. Krohn, Chief
Engineering Branch 2
Division of Reactor Safety
ii
SUMMARY
IR 05000354/2015007; 9/21/15 - 10/23/15; Hope Creek Generating Station; Component Design
Bases Inspection.
The report covers the Component Design Bases Inspection conducted by a team of four NRC
inspectors and two NRC contractors. Two findings of very low safety significance (Green) were
identified, both of which were considered to be non-cited violations (NCVs). The significance of
most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual
Chapter (IMC) 0609, Significance Determination Process. Cross-cutting aspects associated
with findings are determined using IMC 0310, Components Within the Cross-Cutting Areas.
The NRCs program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, Reactor Oversight Process, Revision 5.
NRC-Identified Findings
Cornerstone: Mitigating Systems
Green. The team identified a finding of very low safety significance involving a
non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG
did not establish appropriate acceptance criteria for the time allowed for starting the
residual heat removal (RHR) and core spray pumps during simulated loss-of-coolant
accident/loss-of-offsite power (LOCA/LOP) conditions in the 18-month integrated
emergency diesel generator (EDG) surveillance test (ST) for the vital 4KV buses.
Specifically, the ST acceptance criteria failed to confirm that the pumps started in
accordance with the design basis loading sequence described in the design analyses
and Updated Final Safety Analysis Report Table 8.3-1. PSEGs short-term corrective
actions included reviewing LOCA/LOP test results and plant historical data to confirm
current operability of the RHR and core spray pumps, and initiating corrective action
notifications to determine the appropriate ST acceptance criteria and to trend pump
start times.
The team determined that the failure to specify adequate acceptance limits for the design
basis assigned start times for the RHR and core spray pumps during LOCA/LOP conditions
in the 18-month integrated EDG ST procedure was a performance deficiency. The
performance deficiency was more than minor because it was associated with the procedure
quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone
objective of ensuring the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. The team evaluated the finding in
accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for
Findings at Power, Exhibit 2 - Mitigating Systems Screening Questions, and determined that
the finding was of very low safety significance (Green) because the finding was a design
deficiency that did not result in the loss of operability or functionality. The team determined
that this finding has a cross-cutting aspect in Human Performance, Documentation, in that
PSEG failed to maintain accurate test acceptance documentation to aid plant staff in the
identification of equipment performance that was outside the acceptable limits of design.
(H.7) (Section 1R21.2.1.1)
iii
Green. The team identified a finding of very low safety significance involving a
non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG
did not provide adequate work order instructions for the reinstallation of service water
(SW) pump discharge isolation valve EAHV-2198C following planned valve
maintenance in October 2013. Specifically, the inadequate work order instructions
contributed directly to maintenance technicians installing the valve in the opposite
orientation compared to the intended orientation. PSEG entered this issue into their
corrective action program. In addition, PSEGs corrective actions included
completing several associated technical evaluations, calculations, operability
determinations, and motor-operated valve performance tests.
The team determined that the failure to provide adequate work order instructions for the
installation of safety-related SW valve 2198C was a performance deficiency. The team
determined that this performance deficiency was more than minor in accordance with
IMC 0612, Power Reactor Inspection Report, Appendix B, because it was associated with
the procedure quality attribute of the Mitigating Systems Cornerstone and affected the
cornerstone objective of ensuring the availability, reliability, and capability of systems (SW)
that respond to initiating events to prevent undesirable consequences. Additionally, the
team determined that it was more than minor in accordance with IMC 0612, Appendix E,
Example 3j, because PSEGs associated operability and technical evaluations did not
adequately consider the worst case conditions, resulting in a potential underestimation of
the maximum required opening torque and in a condition where there was a reasonable
doubt on the operability of the C SW train. The team evaluated the finding in accordance
with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at
Power, Exhibit 2 - Mitigating Systems Screening Questions, and determined that the finding
was of very low safety significance (Green) because the finding was a deficiency that
affected the design and qualification of safety-related SW valve 2198C but did not result in
the loss of operability or functionality. The team determined that this finding has a cross-
cutting aspect in Human Performance, Documentation, in that PSEG failed to ensure that
design documentation and work packages were complete, thorough, accurate, and current.
(H.7) (Section 1R21.2.1.2)
Other Findings
None
REPORT DETAILS
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R21 Component Design Bases Inspection (IP 71111.21)
.1
Inspection Sample Selection Process
The team selected risk significant components for review using information contained in
the Hope Creek Probabilistic Risk Assessment (PRA) model and the U. S. Nuclear
Regulatory Commissions (NRC) Standardized Plant Analysis Risk (SPAR) model for the
Hope Creek Generating Station (HCGS). Additionally, the team referenced the Plant
Risk Information e-Book (PRIB) for Hope Creek in the selection of potential components
for review. In general, the selection process focused on components that had a Risk
Achievement Worth (RAW) factor greater than 1.3 or a Risk Reduction Worth (RRW)
factor greater than 1.005. The components selected were associated with both
safety-related and non-safety related systems, and included a variety of components
such as pumps, tanks, diesel engines, batteries, electrical buses, circuit breakers, and
valves.
The team initially compiled a list of components based on the risk factors previously
mentioned. Additionally, the team reviewed the previous component design bases
inspection (CDBI) reports and excluded the majority of those components previously
inspected. The team then performed a margin assessment to narrow the focus of the
inspection to 16 components and 5 operating experience (OE) items. The team selected
the suppression pool and a drywell spray valve to review for large early release
frequency (LERF) implications. The teams evaluation of possible low design margin
included consideration of original design issues, margin reductions due to modifications,
or margin reductions identified as a result of material condition/equipment reliability
issues. The assessment also included items such as failed performance test results,
corrective action history, repeated maintenance, Maintenance Rule (a)(1) status,
operability reviews for degraded conditions, NRC resident inspector insights, system
health reports, and industry OE. Finally, consideration was also given to the uniqueness
and complexity of the design and the available defense-in-depth margins.
The team performed the inspection as outlined in NRC Inspection Procedure (IP)
71111.21. This inspection effort included walkdowns of selected components; interviews
with operators, system engineers, and design engineers; and reviews of associated
design documents and calculations to assess the adequacy of the components to meet
design basis, and licensing basis requirements. Summaries of the reviews performed
for each component and OE sample are discussed in the subsequent sections of this
report. Documents reviewed for this inspection are listed in the Attachment.
2
.2
Results of Detailed Reviews
.2.1
Results of Detailed Component Reviews (16 samples)
.2.1.1 C' Emergency Diesel Generator (Electrical Review) and C 4KV Bus 10A403
a. Inspection Scope
The team inspected the C EDG and its associated 4KV electrical bus (10A403) to verify
that they were capable of performing their design functions in response to transients and
accidents. The team reviewed technical specifications (TSs), operating procedures, and
the Updated Final Safety Analysis Report (UFSAR) to determine the licensing and
operating basis for selected electrical components utilized for starting the C EDG and
for connecting the generator to the safety-related C 4KV bus. The team reviewed the
EDG loading design basis requirements for postulated loss-of-coolant accident (LOCA)
and loss-of-offsite power (LOP) conditions. The team reviewed ST results to verify that
operation of the EDG, and selected emergency core cooling system (ECCS) pumps,
conformed to design basis loading requirements. The team reviewed voltage drop
calculations for the diesel air starting solenoids and the generator field flash circuitry to
assure that adequate voltage was available during limiting design basis conditions. The
team interviewed the system engineer, reviewed the system health report, and
performed a walkdown of the C EDG and the C 4KV bus to assess the observable
material condition. The team also reviewed maintenance records and corrective action
documents to ensure that PSEG properly maintained the components and identified and
corrected deficiencies.
b. Findings
Introduction. The team identified a Green non-cited violation (NCV) Title 10 of the Code
of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, because PSEG did not establish appropriate acceptance
criteria for the time allowed for starting the residual heat removal (RHR) and core spray
pumps during simulated LOCA/LOP conditions in the 18-month integrated EDG ST for
the vital 4KV buses. Specifically, the ST acceptance criteria failed to confirm that the
pumps started in accordance with the design basis loading sequence described in the
design analyses and UFSAR Table 8.3-1.
Description. The team noted that the start time acceptance criteria in the 18-month
integrated C EDG ST for the RHR and core spray pump motors in HC.OP-ST.KJ-0007,
Steps 5.4.8.S and 5.4.8.V, respectively, was 40 seconds and 27 seconds, respectively,
after initiation of a simulated LOCA/LOP condition. Based on a review of the General
Electric (GE) design drawings for the RHR and core spray pump start circuits, the team
noted that the RHR pump was designed to start immediately when 4KV bus power was
available either during a LOCA condition (with offsite power available) or during
LOCA/LOP conditions after the EDG established bus power, and then for the core spray
pump to start six seconds later by a timer circuit which was initiated when the bus power
was available.
3
The team identified that the integrated EDG 18-month ST acceptance criteria did not
correctly incorporate the GE pump start design criteria for the RHR and core spray
pumps. For example, the EDG was designed to establish bus power nominally within
13-seconds after LOCA conditions and the RHR pump should then start immediately, but
the ST acceptance criteria allowed for the pump to start up to 27 seconds later
(40 seconds minus the 13 seconds for power to be established by the EDG after the
LOCA conditions are detected). In addition, although the RHR pump should start
immediately when the EDG breaker closes and 4KV power is available, followed
6 seconds later by the core spray pump in accordance with GE criteria, the acceptance
criteria for the RHR pump was 40 seconds and 27 seconds for the core spray pump.
These acceptance criteria could allow the core spray pump to start before the RHR
pump, resulting in an unanalyzed condition contrary to the design basis loading
sequence described in the design analyses and UFSAR Table 8.3-1. In fact, the team
identified that technicians recorded pump start times in the last integrated B EDG
18-month ST conducted in April 2015 that indicated that the core spray pump had
started before the RHR pump, which would have been contrary to the GE design criteria
for the pump starting sequence. The team also noted that PSEG had failed to identify
this test anomaly during their post-test acceptance review. The team noted that PSEG
had based the ST acceptance criteria on the maximum time for pump flow to be
delivered to the reactor vessel and not the designed pump start time for the RHR and
core spray pumps. Based on this, the team concluded that the ST start time acceptance
criteria for the RHR and core spray pumps was incorrect and non-conservative. During
the inspection, upon further review of the plant historical data and strip chart recordings
from the April 2015 test, PSEG determined that the RHR and core spray pump start
times recorded by the technicians were inadvertently swapped in the ST
documentation as the actual recorded test data confirmed that the RHR pump actually
started before the core spray pump in accordance with the GE design. This
NRC-identified test discrepancy was neither identified nor evaluated by PSEG during
their review of the test results in April 2015.
Notwithstanding, upon further review of the swapped data, the team found that the core
spray pump started approximately 3.8 seconds after the EDG breaker was closed to
establish bus power. However, starting the core spray pump 3.8 seconds after power
was established during a LOCA/LOP was not in accordance with TS acceptance criteria
for the minimum time for the core spray pump to start which was 5 seconds (6 seconds
+/- 1 second) when power was available. For this case, during the inspection, PSEG
engineers reviewed the strip chart recorder record traces for the EDG voltage and
frequency conditions during the core spray pump start and confirmed that the voltage
and frequency recovered within acceptable limits, thereby assuring EDG operability.
Based on a review of the two most recent LOCA/LOP STs for each 4KV vital bus
(completed in the Fall of 2013 and the Spring of 2015), the team also identified several
additional examples of discrepant RHR and core spray pump start time data in the
recorded and accepted test results. These discrepancies included:
1. During the A EDG test in 2013, the core spray pump started only 3 seconds
after bus power was established by the EDG (the TS minimum acceptance
limit was 5 seconds as noted above). During the D EDG test in 2013, the
core spray pump started 4.9 seconds after power was established, which was
4
also not in accordance with the minimum TS acceptance limit. Subsequent
STs performed since 2013 confirmed the proper operation and operability for
the subject core spray pumps.
2. For the A EDG test in 2015, for the corrected data for the B EDG test in
2015, and for the C EDG test in 2013, the recorded test data indicated that
the RHR pump started before the EDG breaker was closed to establish bus
power. The team noted that this condition was not possible based upon a
review of GEs design drawings for the RHR pump start circuit.
Based upon further review and discussions onsite, the team noted that the accuracy of
technicians recorded data was questionable and that some (see item 2 above), but not
all, of the above discrepant conditions could be due to technician response time when
using a stopwatch to record pump start times. Once again, the above NRC-identified
discrepancies were neither identified nor evaluated by PSEG during their review of the
test results at the time of the testing.
The team noted that the non-conservative ST acceptance criteria for the RHR and core
spray pump start times had the potential to mask conditions where equipment performed
outside expected design limits, and these conditions could neither be detected nor
evaluated by PSEG for impact to plant equipment and systems. PSEG initiated
notification (NOTF) 20706543 to evaluate test results for any adverse trend in pump start
times and NOTF 20706542 to evaluate the ST test acceptance criteria for the RHR and
core spray pump start times.
Analysis. The team determined that the failure to specify adequate acceptance limits for
the design basis assigned start times for the RHR and core spray pumps during
LOCA/LOP conditions in the 18-month integrated EDG ST procedure was a performance
deficiency. The team determined that this finding was more than minor because it was
associated with the procedure quality attribute of the Mitigating Systems Cornerstone
and affected the cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Specifically, PSEG failed to identify appropriate EDG loading
acceptance criteria for the RHR and core spray pump motor start timing that was used in
the ST to confirm that safety-related equipment was operating in accordance with the
limits specified in the design analyses. The team evaluated the finding in accordance
with Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance
Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating Systems
Screening Questions, and determined that the finding was of very low safety significance
(Green) because the finding was a design deficiency that did not result in the loss of
operability or functionality. The team determined that this finding had a cross-cutting
aspect in Human Performance, Documentation, in that PSEG failed to maintain accurate
test acceptance documentation to aid plant staff in the identification of equipment
performance that was outside the acceptable limits of design. (H.7)
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, states, in part, that procedures shall include appropriate quantitative or
qualitative acceptance criteria for determining that important activities have been
5
satisfactorily accomplished. Contrary to the above, prior to October 22, 2015, PSEG
had not established appropriate acceptance criteria in HC.OP-ST.KJ-0007, Steps 5.4.8.S
and 5.4.8.V, respectively, for the time allowed for starting the RHR pump and core spray
pumps during simulated LOCA/LOP conditions in the 18-month integrated EDG ST for
the vital 4KV buses.
Specifically, the ST acceptance criteria failed to confirm that the pump(s) starting would
be in accordance with the design basis loading sequence described in design analyses
and UFSAR Table 8.3-1, Emergency Loads Assignment of Class 1E and Selected
Non-Class 1E Loads on Standby Diesel Generator Buses. PSEGs short-term
corrective actions included reviewing LOCA/LOP test results and plant historical data to
confirm current operability of the RHR and core spray pumps and initiating corrective
action NOTFs to determine the appropriate ST acceptance criteria and trend pump start
times. Because this finding was of very low safety significance and because it was
entered into PSEGs corrective action program (NOTFs 20706542 and 20706543), this
violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC
Enforcement Policy. (NCV 05000354/2015007-01, Failure to Establish Appropriate
Acceptance Criteria for RHR and Core Spray Pump Start Times during Simulated
LOCA/LOP Testing)
.2.1.2 Service Water Pump Discharge Valves (EAHV- 2198C and EAHV- 2198D)
a. Inspection Scope
The team reviewed applicable portions of TSs, the UFSAR, and system design basis
documents (DBDs) to identify design basis requirements for service water (SW) pump
discharge valves EAHV-2198 C and D. The team reviewed drawings and vendor
documents to verify that the installed configuration of the valves and their Limitorque
motor operators supported the design basis function under normal and accident
conditions. The team reviewed the valves orientation and their distance from elbows
and from the pumps discharge check valves to assess possible cavitation and flow
disturbances. The team interviewed the system engineer and the motor-operated valve
(MOV) engineer to discuss the valves analyses and operational and maintenance
history, and to verify that PSEG appropriately addressed potentially degraded conditions.
The team reviewed test procedures and recent test results against design bases
documents to verify that acceptance criteria for tested parameters were supported by
calculations or other engineering documents and that individual tests and analyses
served to validate component operation under accident conditions. The team also
reviewed MOV test data and valve operator test traces to validate that the torque
required to open the valves did not exceed the rating of their Limitorque operators. The
team reviewed vendor documentation, system health reports, preventive and corrective
maintenance history, and corrective action system documents to verify that potential
degradation was monitored or prevented, and that scheduled component inspections or
replacements were consistent with trend data and vendor recommendations. The team
conducted several detailed walkdowns to visually inspect the physical/material condition
of the valves, their motor operators and support systems, and to ensure adequate
configuration control.
6
b. Findings
Introduction. The team identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion
V, Instructions, Procedures, and Drawings, because PSEG did not provide adequate
work order instructions for the installation of SW pump discharge isolation valve 2198C
following planned valve maintenance in October 2013. Specifically, the inadequate work
order instructions contributed directly to maintenance technicians installing the valve in
the opposite orientation compared to the intended orientation.
Description. 1EAHV-2198C is the C SW pump discharge isolation valve. The valve is a
28-inch Weir Tricentric butterfly valve with a SMB-1/HBC-4 (60-1) Limitorque motor
operator. The valve has an active safety function in the open position to provide normal
SW flow to the safety-related safety auxiliaries cooling system (SACS) heat exchangers
(HXs) and non-1E reactor auxiliaries cooling system (RACS) HXs, and emergency SW
flow to other systems. PSEG had originally intentionally installed all four 1EAHV-2198
valves in the reverse flow direction to permit the downstream header pressure to seat
the valve tighter to minimize seat leakage during SW pump and strainer on-line
maintenance. During refueling outage 18 (RF18) in October 2013, PSEG performed a
planned refurbishment of the 2198C valve and SMB-1 actuator under work order
60112463-410, Step 1.D. On October 22, 2013, maintenance technicians initiated
NOTF 20626219 to document that while installing the 1EAHV-2198C adapter plate, they
noticed that the valve was installed 180 degrees different from where it was removed
and requested support. The NOTF also documented that the MOV engineer agreed that
reconfiguring the valve operator would be the easiest way to correct the issue. In an
October 23, 2013, update to the NOTF, maintenance stated that they had applied match
marks to ensure that the valve would be installed in the same orientation, but during the
course of the work the match marks were erased. Maintenance also updated the NOTF
to reflect that they had identified that the 2198 valve installation orientation design
specification was not documented in valve drawing M-10-1 or the vendor manual (VTD
323981) as expected. The team also noted that several diagrams within the work order
depicted the wrong valve orientation and may have contributed to the configuration
control error. Finally, the team noted that there was no documented evaluation of the
impact of this misalignment and configuration error prior to operations declaring the C
SW pump operable following the 2198C maintenance on October 23. PSEG initiated
NOTF 20705874 for this operability screening performance gap.
Based on the narrative logs, the team noted that operators started and stopped the
C SW pump several times during the period October 23 - 26, 2013 (with proper
function of the 2198C). At 10:59 p.m. on October 26, 2013, operators started the C SW
pump (in support of the ongoing A LOCA/LOP ST), but the 2198C failed to open.
Operators promptly initiated NOTF 20627235 and entered an unplanned TS limiting
condition for operation (LCO) for the C SW pump. PSEG performed troubleshooting
and identified that a high opening torque (> ~ 9500 ft-lbs) tripped the torque switch
removing power to the valve actuator and resulting in a failure to stroke. PSEG bumped
up the torque switch setting to ~ 13,200 ft-lbs and successfully stroked the valve open.
At 4:44 p.m. on October 27, 2013, while stroking open the valve, engineers recorded a
maximum opening torque of 10,201 ft-lbs via a MOV dynamic trace. At 8:53 p.m. on
October 27, 2013, operators declared the C SW pump operable and exited the TS LCO.
7
The team noted that there was no apparent documented evaluation of the cause of the
unexpected high opening torque or an assessment of the recorded maximum opening
torque (10,201 ft-lbs) relative to the maximum expected opening torque under design
basis conditions compared to the MOVs weak link analysis and Limitorque limits.
On February 7, 2014, Weir Valves & Controls USA filed an Interim 10 CFR Part 21
Report for a potential failure associated with Weir valves installed in the forward flow
orientation (like the 2198C valve). Based on testing (by PSEG and Weir in December
2013), Weir determined that there existed an unseating load which was not accounted
for in Weir's Tricentric triple offset product line operator sizing methodology. A potential
operator sizing issue could exist on Tricentric valves which have an open safety function
during an event. Weir identified that the direction of flow across the non-symmetrical
disc had an impact on the torque required to open/close the valve. PSEG initiated
NOTF 20639544 and order 70163546 to evaluate and resolve the potential issue. For
Hope Creek, PSEG determined that 17 MOVs could be affected by this issue. The
preliminary evaluation under order 70163546-020 only identified one potential
operational issue requiring any further evaluation (the 1EAHV-2198C valve that
maintenance had installed backwards during RF18, prior to the issuance of the Part 21).
For this installation, the maximum differential pressure (DP) only exists on the inlet side
of the disc during disc opening when the C SW pump is the first pump started in the
A SW loop. Engineering determined that the required stem torque to open the 2198C
valve was above the component rating. PSEGs MOV program procedure guidance
allows this condition (up to 113 percent of the rated torque) for a limited number of
strokes (100). PSEG also initiated NOTF 20673076 to reverse the flow direction of the
valve during RF20 in October 2016, so the allowed strokes would not be exceeded. In
addition, PSEG performed a technical evaluation to assess the adequacy of MOV
1EAHV-2198C in its installed orientation and evaluated it for a Use-As-Is interim
disposition as defined by PSEG procedure CC-AA-11 (70163546-070).
While performing the technical evaluation, engineering identified that the 2198C opening
torque would exceed the 113 percent rated torque (14,464 ft-lbs) if they used the SW
pump shutoff head in their calculation of maximum DP. PSEG contracted with MPR
Associates to perform a more detailed evaluation. MPRs associated calculation
reduced the required opening torque from 17,479 ft-lbs to 13,814 ft-lbs (108 percent of
the Limitorque limit). The team observed that PSEGs associated technical evaluation
noted the high opening torque (10,201 ft-lbs) recorded on October 27, 2013; however,
the evaluation only cited it as evidence that the opening torque remained acceptable
when opening the 2198C valve (while starting the C SW pump) with the A SW pump
running under normal operating conditions (less than the maximum DP expected under
design basis conditions). The team noted that there was no apparent documented
evaluation comparing the recorded actual opening torque (10,201 ft-lbs) to the expected
opening torque (calculated based on the DP at the time) to ensure validity and
applicability of the Weir calculation methodology.
During the 2015 CDBI, based on the extremely high opening torque recorded under
normal conditions and the valves lack of margin, the team questioned the operability of
the 2198C valve to function under design basis conditions (starting the C SW pump
without the A SW pump running). Based on the teams concern, engineering initiated
8
NOTF 20704783 to perform a technical evaluation to determine if the 2198C actuator
was capable of opening the valve under all required conditions based on the actual
measured data. Engineering used conservative assumptions and appropriate
engineering rigor to determine the approximate DP that existed when the 2198C valve
opened on October 27, 2013, when the dynamic MOV trace recorded an opening torque
of 10,201 ft-lbs. Engineering estimated the DP at 50.2 pounds square inch differential
(PSID). PSEG entered this DP into the Weir spreadsheet (provided with the associated
Interim Part 21 Report) and noted that it resulted in a much lower required opening
torque (8,375 ft-lbs compared to 10,201 ft-lbs). The apparent disparity between the
measured value (10,201 ft-lbs) and the calculated value (8,375 ft-lbs) affirmed the teams
concern that other factors may be at play affecting the torque required to open this
particular valve and/or called into question the validity of the Weir spreadsheet
calculation for this particular configuration (parallel pump operation, closing the
discharge isolation valve with the parallel pump running). Based on the 21.8 percent
difference between the calculated Weir expected opening torque of 8,375 ft-lbs at 50.2
PSID and the measured torque of 10,201 ft-lbs, PSEGs technical evaluation
(70180794-010) added an additional 3,039 ft-lbs (22 percent) to the Weir expected
maximum opening torque of 13,814 ft-lbs at the MPR calculated maximum DP of 80.7
PSID to bound the potential impact.
This resulted in an expected maximum opening torque of 16,853 ft-lbs utilizing the Weir
Tricentric unseating torque evaluation model. However, PSEG recognized that this final
expected torque would exceed the Limitorque 113 percent rating of 14,464 ft-lbs,
requiring additional analysis. To ensure sufficient torque margins, PSEG contracted with
Kalsi Engineering to perform H4BC gear box torque analyses for the 2198C valve.
Based on the Kalsi analysis, the EAHV-2198C H4BC gear box can continue to operate
safely for at least 9 cycles (open strokes) at an opening torque level up to 20,000 ft-lbs.
In addition, PSEGs technical evaluation noted that the torque switch is bypassed during
C SW pump starts under LOCA/LOP conditions ensuring that the torque switch would
not preclude valve opening if the open torque exceeded 13,200 ft-lbs. Based on the
Kalsi analysis and bypass of the open torque switch under accident conditions, the team
concurred with PSEGs determination that the 2198C valve remained operable (although
non-conforming).
The team noted that PSEGs technical evaluation also credited starting the C SW pump
twice in RF19 in April 2015, with the A SW pump not running, demonstrating that the
EAHV-2198C valve was fully capable of opening under the worst case condition (highest
expected DP) without tripping the torque switch (not needing the additional torque
margin calculated by Kalsi). The team independently reviewed the operator narrative
logs and plant historical SW flow data associated with the two credited C SW pump
starts to verify that the conditions actually represented worst case conditions. The team
confirmed that the A SW pump was indeed out of service when operators started the
C SW pump on both occasions. However, the team identified that the A SW pump was
also not running on both occasions when the operators stopped the C SW pump. More
importantly, the A SW pump discharge pressure was not present on the backside of the
2198C valve while it was closing (prior to the subsequent opening). The team recalled
that the Weir Interim Part 21 Report stated that the DP across the valve while closing the
valve made a noted difference to the subsequent unseating torque when re-opening the
9
valve. The team noted that the A SW pump was running when closing the 2198C on
both occasions in October 2013 prior to the 2198C experiencing a relatively high torque
on the subsequent opening. Thus, based on the facts and actual plant configuration
during the October 2013 and April 2015 C SW pump starts, the team determined that
the C SW pump starts in April 2015 did not adequately demonstrate the capability of the
2198C valve to function under worst case design basis conditions, and could not be
credited solely to confirm continued operability of the 2198C. Also, based on the
information provided during the inspection, the team noted that Weirs testing in support
of their February 2014 Interim Part 21 Report did not include parallel pump combinations
and potential effects of closing the subject valve with the redundant (parallel) pump in
service.
During the inspection, the team also noted that engineering did not completely and
accurately follow PSEG procedure CC-AA-11, Nonconforming Materials, Parts, or
Components, during their technical evaluation in response to the Weir Interim Part 21
Report (70163546-070). In particular, the team identified that engineering did not enter
the operability determination process (OP-AA-108-115) as required by procedure
CC-AA-11 for safety-related components which would likely had resulted in a
determination of operable but non-conforming for the degraded 2198C valve. The team
noted that this represented a minor procedure violation; however, failing to properly
classify the condition as operable non-conforming represented a potential missed
opportunity as PSEG management may have elected to correct the condition in May
2015 (RF19). PSEG initiated NOTF 20707031 for this issue.
The team noted that PSEG identified the underlying performance deficiency (less than
adequate work order instructions and drawings) associated with the issue of concern
discussed above. However, in accordance with NRC IMC 0612, NRC-identified findings
include issues initially identified by the licensee to which the inspector has identified a
previously unknown weakness in the licensees classification, evaluation, or corrective
actions associated with the licensees correction of a finding or violation (i.e., NRC
added value). As noted above, the NRC-identified PSEG shortcomings included:
operability determination screenings and evaluations, procedure use and adherence,
and adequacy of engineering rigor and questioning attitude in technical evaluations.
Analysis. The team determined that the failure to provide adequate work order
instructions for the installation of safety-related SW isolation valve 2198C was a
performance deficiency. Specifically, PSEG did not provide adequate instructions and
drawings for the reinstallation of valve 2198C, which was previously removed for
maintenance, nor did PSEG adequately analyze the resulting condition. The team
determined that this performance deficiency was more than minor because it was
associated with the procedure quality attribute of the Mitigating Systems Cornerstone
and affected the cornerstone objective of ensuring the availability, reliability, and
capability of systems (SW) that respond to initiating events to prevent undesirable
consequences. Additionally, the team determined that it was more than minor in
accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, and
Appendix E, Example 3j, because PSEGs associated operability and technical
evaluations did not adequately consider the worst case conditions, resulting in a
10
potential underestimation of the maximum required opening torque and in a condition
where there was a reasonable doubt on the operability of the C SW train.
The team evaluated the finding in accordance with IMC 0609, Appendix A, The
Significance Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating
Systems Screening Questions, and determined that the finding was of very low safety
significance (Green) because the finding was a deficiency that affected the design and
qualification of safety-related SW valve 2198C but did not result in the loss of operability
or functionality. The team determined that this finding had a cross-cutting aspect in
Human Performance, Documentation, in that PSEG failed to ensure that design
documentation and work packages were complete, thorough, accurate, and current.
(H.7)
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, states in part, that activities affecting quality shall be prescribed by
documented instructions, procedures, or drawings, of a type appropriate to the
circumstances and shall be accomplished in accordance with these instructions,
procedures, or drawings. Contrary to the above, on October 22, 2013, PSEG did not
provide proper procedures for the installation of SW pump discharge isolation valve
EAHV-2198C in work order 60112463-410, Step 1.D, after it was removed from service
during RF18 for maintenance activities. Because this violation is of very low safety
significance and has been entered into PSEGs corrective action program (NOTF
20704783), this violation is being treated as a NCV consistent with Section 2.3.2 of the
NRC Enforcement Policy. (NCV 05000354/2015007-02, Inadequate Work Order
Instructions and Drawings Resulting in Improper Installation of a Safety-Related
SW Valve)
.2.1.3 High Pressure Coolant Injection Steam Supply Isolation Valve (FD-HV-F001) and Steam
Supply Piping
a. Inspection Scope
The team inspected the high pressure coolant injection (HPCI) turbine steam supply
outboard containment isolation (FD-HV-F001) to verify that it was capable of performing
its design function in response to transients and accidents. The normally closed
FD-HV-F001 valve is required to open for the HPCI system to perform its ECCS function
and is required to close to isolate the main steam line and reactor vessel to prevent
depressurization in case of a HPCI steam line break. The team reviewed applicable
portions of Hope Creeks TSs, the UFSAR, and the HPCI system DBD to identify design
basis requirements for FD-HV-F001.
The team reviewed design calculations, including environmental qualifications, valve
specifications, and the operating history to verify that the valve was acceptable for HPCI
service, and to verify that it met the applicable American Society of Mechanical
Engineers (ASME) Code in-service testing requirements. The team reviewed a sample
of ST results to verify that valve performance met the acceptance criteria and that the
criteria were consistent with the design basis. The team interviewed the system
engineer and reviewed MOV diagnostic test results and trending to assess valve
11
performance capability and design margin. The team reviewed a sample of HPCI
system corrective action NOTFs, technical evaluations, the HPCI system health report,
and applicable test results to determine if there were any adverse operating trends and
to ensure that PSEG adequately identified and addressed any adverse conditions. The
team also performed several walkdowns of the valve, adjacent area, accessible portions
of the HPCI system steam piping, and associated control room instrumentation to
assess the material condition, operating environment, and configuration control.
b. Findings
No findings were identified.
.2.1.4 C and D Service Water Strainers and Motors (1C-F-509 & 1D-F-509)
a. Inspection Scope
The team inspected the C and D SW strainers to evaluate whether they were capable
of meeting their design basis and operational requirements to pass the required SW flow
rate while maintaining the SW system reasonably clean, to prevent debris from plugging
the safety-related SACS HXs, and to prevent a high pressure drop across the strainers
under all accident conditions. The team evaluated the strainers pressure drop and the
adequacy of their continuous backwash function to ensure continuous operation without
impeding the proper operation of the SW System. The team reviewed monthly testing,
flow rates and pressure drops as well as acceptance criteria affecting the strainers
function to verify that they were capable of performing their safety function and to
determine if PSEG had adequately evaluated the potential for strainer degradation. The
team interviewed the system and design engineers to assess the material condition of
the strainers and scheduled maintenance activities. The team conducted several
detailed walkdowns to visually inspect the physical/material condition of the strainers,
their motors, and their support systems to validate their design details such as the
seismic support of the cantilevered motor located at the top of each strainer, and to
ensure adequate configuration control. Finally, the team reviewed corrective action
documents and system health reports to evaluate whether there were any adverse
operating trends and to assess PSEGs ability to evaluate and correct problems.
b. Findings
No findings were identified.
.2.1.5 Safety Auxiliaries Cooling System Air-Operated Valves EG-AOV-2457B and
EG-AOV-2520B
a. Inspection Scope
The team inspected SACS air operated valves (AOVs) EG-AOV-2457B and
EG-AOV-2520B to verify that they were capable of performing their design function. The
SACS system has a safety-related function to provide cooling water to the engineered
safety features (ESFs) equipment, including the RHR pumps and HXs, during normal
12
operation, normal plant shutdown, LOP, and a LOCA. The 2457B valve is the SACS HX
temperature control bypass isolation valve. This valve is normally open and has an
active safety function to close to prevent flow diversion around the SACS HXs, which
could prevent the SACS system from performing its design heat removal safety function.
This valve has no safety function in the open position. The 2520B valve is the B RHR
pump cooler SACS supply valve. This valve has an active safety function in the open
position to provide SACS cooling water flow to the B RHR pump seal and motor bearing
coolers. This valve has no safety function in the closed position. The valve fails open on
loss of power or air and automatically opens on a B RHR pump start.
The team reviewed the UFSAR, calculations, associated TSs, and procedures to identify
the design basis requirements of the valves. The team also reviewed accident system
alignments to determine if component operation would be consistent with the design and
licensing bases assumptions. The team also reviewed valve testing procedures and
valve specifications to ensure consistency with design basis requirements. The team
reviewed periodic verification diagnostic test results and stroke test documentation to
verify acceptance criteria were met and consistent with the design basis. The team
interviewed the AOV program engineer to gain an understanding of maintenance issues
and overall reliability of the valves. The team conducted a walkdown to assess the
material condition of the valves, associated piping and supports, and to verify that the
installed valve configuration was consistent with design basis assumptions and plant
drawings. The team also reviewed the maintenance and operating history of the valves,
the SACS system health report, and applicable system test results to determine if there
were any adverse operating trends and to ensure that PSEG adequately identified and
addressed any adverse conditions. Finally, the team reviewed specific corrective action
documents to verify that PSEG appropriately identified and resolved deficiencies, and
properly maintained the valves.
b. Findings
No findings were identified.
.2.1.6 C 125 Volt Direct Current Battery
a. Inspection Scope
The team reviewed the design, testing, and operation of the C 125 volt direct current
(Vdc) station battery (1CD411) to verify that it was capable of performing its design
function of providing a reliable source of direct current (DC) power to connected loads
under operating, transient, and accident conditions. The team reviewed design
calculations to assess the adequacy of the batterys sizing to ensure that it could power
the required equipment for a sufficient duration, and at a voltage above the minimum
required for equipment operation. The team reviewed short circuit and breaker
coordination calculations to ensure that breakers were adequately sized and were
capable of interrupting short circuit faults. The team verified that proper breaker
coordination existed to provide adequate isolation of the affected portion of the circuit.
The team reviewed battery test results to ensure that the testing was in accordance with
13
design calculations, the HCGS TSs, and industry standards, and that the results
confirmed acceptable performance of the battery. The team interviewed design
engineers regarding design margin, operation, and testing of the DC system. The team
performed a walkdown of the battery, DC buses, battery chargers, and associated
distribution panels to assess the material condition, configuration control, and the
operating environment. Finally, the team reviewed a sample of corrective action NOTFs
to ensure that PSEG identified and properly corrected issues associated with the
C 125 Vdc (1CD411) station battery.
b. Findings
No findings were identified.
.2.1.7 Suppression Pool Water Level, Temperature, and Water Quality Control
a. Inspection Scope
The team inspected the suppression pool to verify that it was capable of performing its
design function. The team reviewed the design basis documents pertaining to the
suppression pool (torus) and the applicable sections of the UFSAR to determine the
design requirements. The team also reviewed torus internal coating inspection results
from inspections performed during the last two refueling outages to assess the material
condition and structural integrity of the torus. The team reviewed recent pressure
suppression chamber to drywell vacuum breaker and pressure suppression chamber to
reactor building vacuum breaker test results to verify that the vacuum breakers remained
operable and capable of performing their design function supporting suppression pool
integrity. The team also reviewed associated corrective action NOTFs, and applicable
instrumentation and control test results for the suppression pool temperature, pressure,
and level instruments to determine if there were any adverse trends and to ensure that
PSEG adequately identified and addressed any adverse conditions. The team
conducted an extensive walkdown of the accessible portions of the exterior of the torus
structure to assess the material condition (including evidence of leakage), structural
supports, potential hazards, and configuration control.
b. Findings
No findings were identified.
.2.1.8 C Emergency Diesel Generator Load Sequencer
a. Inspection Scope
The team reviewed TSs, the UFSAR, and system DBDs to identify design basis
requirements for the emergency load sequencer (ELS). The team reviewed drawings
and vendor documents to verify that the installed configuration supported the design
basis function under accident conditions. The team interviewed the system engineer,
reviewed the system health report, and performed several walkdowns of the ELS cabinet
to assess the observable material condition and operating environment. The team also
14
verified that the location and installation of the cabinet mounting fasteners were in
accordance with the installation drawings to ensure seismic adequacy. The team
reviewed test procedures and recent test results against DBDs to verify that acceptance
criteria for the tested sequenced time parameters were supported by calculations or
other engineering documents and that individual tests and analyses served to validate
component operation under accident conditions. The team reviewed vendor
documentation, system health reports, preventive and corrective maintenance history,
and corrective action system documents in order to verify that potential degradation was
monitored or prevented, and that scheduled component inspections or replacements
were consistent with vendor recommendations.
b. Findings
No findings were identified.
.2.1.9 Emergency Diesel Generator Fuel Oil Transfer Pumps
a. Inspection Scope
The team reviewed applicable portions of TSs, the UFSAR, and system DBDs to identify
design basis requirements for the EDG fuel oil transfer pumps (FOTPs). The team
inspected the FOTPs to evaluate whether they were capable of meeting their design
basis and operational requirements to maintain each EDG fuel oil day tank (FODT) with
sufficient fuel oil and with a flow rate greater than the peak fuel oil consumption rate of
the EDGs under all accident conditions, including LOP. The team evaluated the pumps
net positive suction head (NPSH) and suction under the minimum level at the storage
tank to ensure that pump operation would not be disrupted. The team reviewed the
sizing of the FODTs and the levels associated with the FOTPs start and stop to verify
that the TS-required fuel oil quantity was not compromised. The team reviewed flow rate
testing and in-service test (IST) results to verify that the pump performance bounded the
analyzed performance of each of the eight FOTPs, and to determine if PSEG had
adequately evaluated the potential for pump degradation. The team interviewed the
system and design engineers to assess the material condition of the FOTPs and
scheduled maintenance activities. The team also conducted several detailed walkdowns
to visually inspect the physical/material condition of the FOTPs and their support
systems, to validate the data associated with the instruments supporting FOTP
operation, and to ensure adequate configuration control. Finally, the team reviewed
corrective action documents and system health reports to evaluate whether there were
any adverse operating trends and to assess PSEGs ability to evaluate and correct
problems.
b. Findings
No findings were identified.
15
.2.1.10 A Safety Auxiliaries Cooling System Expansion Tank and A Safety Auxiliary
Cooling System Piping Integrity
a. Inspection Scope
The team reviewed the design, testing, inspection, and operation of the A SACS
expansion tank (1-EG-1AT-205), its associated tank level instruments, and associated
piping to evaluate whether it could perform its design basis function. The team reviewed
design calculations, drawings, and vendor specifications (including tank sizing and level
uncertainty analysis) to evaluate the adequacy and appropriateness of design
assumptions and operating limits. The team interviewed engineers, and reviewed test
records, alarm response procedures, and operating procedures to evaluate whether
maintenance and testing were adequate to ensure reliable operation, and to evaluate
whether those activities were performed in accordance with regulatory requirements,
industry standards, and vendor recommendations. The team also conducted walkdowns
of the tank and associated piping and supports to assess the material condition. Finally,
the team reviewed corrective action documents and system health reports to evaluate
whether there were any adverse trends associated with the A SACS expansion tank
and to assess PSEG's ability to evaluate and correct problems.
b. Findings
No findings were identified.
.2.1.11 A 250 Volt, Direct Current Motor Control Center (10D251)
a. Inspection Scope
The team reviewed the design, testing, and operation of the A 250 Vdc motor control
center (MCC) to verify its ability to meet design basis requirements during plant
transients and accidents. The MCC provides 250 Vdc power to HPCI system main and
auxiliary components, including the HPCI steam supply isolation valve (FD-HV-F001).
The team interviewed design engineers regarding design margin, operation, and testing
of the DC system. The team performed several walkdowns of the MCC to assess the
material condition, configuration control, and the operating environment. The team
reviewed HPCI MCC internal inspection preventive maintenance (PM), battery sizing
calculations, and voltage drop calculations. Finally, the team reviewed a sample of
corrective action NOTFs to ensure that PSEG identified and properly corrected issues
b. Findings
No findings were identified.
16
.2.1.12 Drywell Spray Valve (BC-HV-F021B)
a. Inspection Scope
The team inspected the B drywell spray valve (BC-HV-F021B) to verify that it was
capable of performing its design function in response to transients and accidents. The
normally closed drywell spray valve has a safety function in the open position to allow
the RHR system to perform its containment cooling function of reducing and maintaining
primary containment pressure and temperature to within acceptable limits following a
LOCA. The drywell spray valve also has a safety function to close to provide a primary
containment isolation. The team reviewed applicable portions of Hope Creeks TSs, the
UFSAR, and the RHR system DBD to identify design basis requirements for
BC-HV-F021B. The team reviewed design calculations, including environmental
qualifications, valve specifications, and the operating history to verify that the valve was
acceptable for RHR service, and to verify that it met the applicable ASME Code
in-service testing requirements. The team reviewed a sample of ST results to verify that
valve performance met the acceptance criteria and that the criteria were consistent with
the design basis. The team interviewed the system engineer, and reviewed MOV
diagnostic test results and trending to assess valve performance capability and design
margin. The team reviewed a sample of related RHR system corrective action NOTFs,
technical evaluations, the RHR system health report, corrective and preventive
maintenance records, and applicable test results to determine if there were any adverse
operating trends and to ensure that PSEG adequately identified and addressed any
adverse conditions. The team also performed a walkdown of both drywell spray valves
(F021A and F021B), accessible portions of the RHR system piping, and associated
control room instrumentation to assess the material condition, operating environment,
and configuration control.
b. Findings
No findings were identified.
.2.1.13 C Residual Heat Removal Pump Breaker, C Service Water Pump Breaker, and
C Emergency Diesel Generator Output Circuit Breaker
a. Inspection Scope
The team reviewed TSs, the UFSAR, and system DBDs to identify design basis
requirements for the C RHR and C SW pump motors and the C EDG output circuit
breakers. The team reviewed voltage drop calculations for the breaker closing circuits to
assure that adequate voltage was available during limiting design basis conditions. The
team also reviewed the current system health report, selected drawings and
calculations, maintenance and test procedures, and corrective action NOTFs associated
with the C RHR and C SW pump motors and the C EDG output circuit breakers.
Specifically, the team reviewed the pump maximum brake horsepower requirements to
confirm the adequacy of the motor capability to supply power during worst case design
conditions. The team reviewed the adequacy of motor starting and running during
degraded offsite voltage conditions coincident with a postulated design basis accident.
17
The team verified motor overcurrent relay settings and periodic relay calibration test
results for adequacy to ensure reliable motor operation during the most limiting design
basis operating conditions. The team interviewed the system engineers and performed
several walkdowns of the motors and the associated 4KV switchgear, including the
control room panels, to assess the observable material condition, configuration control,
and operating environment.
b. Findings
No findings were identified.
.2.1.14 Emergency Instrument Air Compressor (10K100) and Instrument Air Header Piping
a. Inspection Scope
The team reviewed the design, testing, inspection, and operation of the emergency
instrument air compressor (EIAC) and instrument air header piping to evaluate whether
they could perform their design basis function. The non-safety related service air (SA)
system supplies normal air to the instrument air (IA) system. The IA system is also
non-safety related; however, it is important to safety and has a high risk function to
provide clean, dry, oil-free air at the normal temperature and pressure for the
air-operated instruments and devices throughout the plant. The EIAC provides the
motive force required to maintain IA system pressure should both SA compressors be
non-operational.
The team reviewed design calculations, drawings, system modifications, and vendor
specifications to evaluate the adequacy and appropriateness of design assumptions and
operating limits. The team interviewed engineers, and reviewed test records, alarm
response procedures, and operating procedures to evaluate whether maintenance and
testing were adequate to ensure reliable operation, and to evaluate whether those
activities were performed in accordance with regulatory requirements, industry
standards, and vendor recommendations. The team also conducted several walkdowns
of the SA compressors, IA dryers, EIAC, local alarm panels, associated control room
instrumentation, and accessible IA piping and supports to assess the material condition,
configuration control, and operating environment. Finally, the team reviewed corrective
action documents and system health reports to evaluate whether there were any
adverse trends associated with the EIAC or IA system and to assess PSEG's ability to
evaluate and correct problems.
b. Findings
No findings were identified.
18
.2.1.15 C 125Vdc Bus 10D430 and Distribution Panel 1CD417
a. Inspection Scope
The team inspected the C 125 Vdc bus (10D430) and DC distribution panel (1CD417)
to verify that they were capable of meeting their design basis requirements to distribute
preferred power to safety-related essential loads. The team reviewed the one-line
diagrams, control schematics, and the design basis as defined in the UFSAR to verify
the adequacy of the 125V bus to supply adequate voltage and current to the loads. The
team reviewed the associated voltage drop, load flow, and short circuit calculations to
verify that adequate voltage was available to components supplied by the bus under
worst case loading and degraded voltage conditions. The team reviewed the bus supply
and feeder breaker ratings and trip settings to verify that protection coordination was
provided for the loads and for the feeder conductors. The team reviewed vendor
specifications, nameplate data, and calculations related to the 125V bus supply. The
team interviewed system and design engineers to answer questions that arose during
document reviews to determine the adequacy of maintenance and configuration control.
The team performed several walkdowns of the 10D430 bus and associated DC
distribution panel to assess the material condition, configuration control, and the
operating environment. Finally, the team reviewed corrective action NOTFs and system
health reports to verify that PSEG appropriately identified and resolved deficiencies.
b. Findings
No findings were identified.
.2.1.16 A Standby Liquid Control Pump and Standby Liquid Control Tank
a. Inspection Scope
The team reviewed applicable portions of TSs, the UFSAR, and the system DBD to
identify design basis requirements for the standby liquid control (SLC) system. The
team inspected the A SLC pump and SLC tank to evaluate whether the pump, taking
suction from the tank, was capable of meeting its design basis and operational
requirements to provide the required borated water to the reactor vessel under the most
limiting accident conditions. The team evaluated the ability of the SLC pump to deliver
the design and licensing bases flow rates while the redundant B pump was operating
and assessed possible interactions between the two pumps. The team reviewed
surveillance testing using the SLC test tank, as well as IST acceptance criteria
associated with the SLC pump. The team also validated the tank capacity and reviewed
its operational capabilities with respect to Anticipated Transients Without Scram (ATWS)
and the reactor pressure vessel (RPV) control portion of the emergency operating
procedures (EOPs). The team also verified that the pump performance bounded the
flow requirements in the safety analysis and verified that PSEG had adequately
evaluated the potential for pump degradation. The team interviewed system and design
engineers as well as the IST Program Manager to gather information regarding the
condition of the pump, adequacy of pump maintenance, and outstanding issues affecting
the pump. The team conducted several detailed walkdowns of the pump, SLC tank,
19
associated support components and instruments, and control room indications to visually
inspect the physical/material condition and to ensure adequate configuration control.
Finally, the team reviewed corrective action documents and system health reports to
evaluate whether there were any adverse operating trends and to assess PSEGs ability
to evaluate and correct problems.
b. Findings
No findings were identified.
.2.2
Review of Industry Operating Experience and Generic Issues (5 samples)
The team reviewed selected OE issues for applicability at Hope Creek. The team
performed a detailed review of the OE issues listed below to verify that PSEG had
appropriately assessed potential applicability to site equipment and initiated corrective
actions when necessary.
.2.2.1 NRC Information Notice 2013-14: Potential Design Deficiency in Motor-Operated Valve
Control Circuitry
a. Inspection Scope
The team assessed PSEGs applicability review and disposition of NRC Information
Notice (IN) 2013-14. This information notice discussed recent industry OE regarding a
potential control circuit design deficiency in MOVs that could result in incorrect valve
position indication with the valve in an improper position during a LOCA. The team
reviewed PSEGs evaluation (70158062) performed in response to this OE. In addition,
the team reviewed design drawings and circuit diagrams to assess PSEGs review of the
issue.
b. Findings
No findings were identified.
.2.2.2 NRC Information Notice 2011-12: Reactor Trips Resulting from Water Intrusion into
Electrical Equipment
a. Inspection Scope
The team assessed PSEGs applicability review and disposition of NRC IN 2011-12.
The NRC issued the IN to inform licensees about OE regarding recent events involving
water intrusion into electrical equipment that resulted in reactor trips. In addition, the IN
described the root causes and corrective actions taken to prevent recurrence. The team
assessed PSEGs evaluation of the IN as it applied to HCGS, including their review of
the electrical equipment design to ensure that it remained reliable and that there were no
vulnerabilities associated with possible water intrusion events. The inspection included
a review of corrective action documents, interviews with electrical and design
engineering and operations personnel, and a complete walkdown of all accessible
20
safety-related and non-safety related electrical panels, MCCs, electrical cable spreading
rooms, and switchgear rooms.
b. Findings
No findings were identified.
.2.2.3 NRC Information Notice 2012-03: Design Vulnerability in Electric Power System
a. Inspection Scope
The team assessed PSEGs applicability review and disposition of NRC IN 2012-03.
The NRC issued the IN to inform licensees about OE involving the loss of one of the
three phases of the offsite power circuit. The team assessed PSEGs evaluation of the
IN as it applied to Hope Creek to confirm that PSEG performed an adequate review and
assessment of the issue, and to verify that adequate indications and procedures were
available to the operators to take appropriate actions when necessary. The inspection
also included a review of associated corrective action documents.
b. Findings
No findings were identified.
.2.2.4 NRC Information Notice 2013-17: Significant Plant Transient Induced by Safety-Related
Direct Current Bus Maintenance at Plant
a. Inspection Scope
The team assessed PSEGs applicability review and disposition of NRC IN 2013-17 for
Hope Creek. The NRC issued the IN to inform licensees of recent OE involving the loss
of one train of a DC distribution system at power in a nuclear power plant. The team
reviewed PSEGs evaluation of the systems, components, processes, and procedures
described in the assigned OE document to determine if similar deficiencies could
represent potential operability issues. PSEG determined that Hope Creek was not
vulnerable to the failure as their design differed in that the HCGS DC system has a fuse
with a 4 second time delay (rated at 500 percent) to allow the fuse to pass normal
current and surges instead of a breaker. The team reviewed the adequacy of PSEGs
determination that there were no similar deficiencies that could represent potential
operability issues and that the OE was not applicable at Hope Creek.
b. Findings
No findings were identified.
21
.2.2.5 NRC Information Notice 2010-03: Failures of Motor-Operated Valves due to Degraded
Stem Lubricant
a. Inspection Scope
The team assessed PSEGs applicability review and disposition of NRC IN 2010-03.
This IN discussed industry OE regarding recent failures and corrective actions for MOVs
due to degraded lubricant on the valve stem and actuator stem nut threaded area. The
team verified that PSEG entered the OE into their corrective action program (CAP) for
review (NOTF 20453813). The team reviewed PSEGs evaluation (70108019)
performed in response to this OE as well as PSEGs follow-up actions. The team also
reviewed changes to maintenance procedures and lubrication databases made in
response to this OE. In addition, the team assessed the adequacy of the PSEGs
corrective actions during walkdowns of various MOVs.
b. Findings
No findings were identified.
4.
OTHER ACTIVITIES
4OA2 Identification and Resolution of Problems (IP 71152)
a. Inspection Scope
The team reviewed a sample of problems that PSEG had previously identified and
entered into the CAP. The team reviewed these issues to verify an appropriate threshold
for identifying issues and to evaluate the effectiveness of corrective actions. In addition,
the team reviewed NOTFs written on issues identified during the inspection to verify
adequate problem identification and incorporation of the problem into the CAP. The
specific corrective action documents that the team sampled and reviewed are listed in
the Attachment.
b. Findings
No findings were identified.
4OA6 Meetings, including Exit
On October 23, 2015, the team presented the inspection results to Mr. Eric Carr,
Plant Manager, and other members of the PSEG staff. The team verified that no
proprietary information was retained by the inspectors or documented in the report.
A-1
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
PSEG Personnel
E. Carr, Plant Manager
M. Conroy, AOV Program Engineer
A. Contino, 4KV System Manager
S. DelMonte, Branch Manager
K. Denny, SW System Manager
P. Duca, Senior Engineer, Regulatory Assurance
D. Dunn, RHR System Manager
A. Ghose, Design Engineer Civil Structural
J. Lane, Design Engineer
T. MacEwen, Hope Creek Compliance Engineer
S. Madden, Design Manager
S. Nevelos, Regulatory Assurance Manager
C. Payne, HPCI & RCIC System Manager
M. Peterson, IA System Manager
C. Reed, Remote Shutdown System Manager
N. Rock, SACS System Manager
C. Torres, NSSS Manager
A. Tramontana, Hope Creek Programs Engineering Manager
Z. VanNess, Design Engineer
E. Wagner, Capital Projects
NRC personnel
C. Cahill, Senior Reactor Analyst
S. Haney, Resident Inspector
J. Hawkins, Senior Resident Inspector
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Open and Closed
Failure to establish appropriate
acceptance criteria for RHR and core
spray pump start times during
simulated LOCA/LOP testing.
(Section 1R21.2.1.1)
Inadequate work order instructions
and drawings resulting in improper
installation of a safety-related SW
valve. (Section 1R21.2.1.2)
A-2
LIST OF DOCUMENTS REVIEWED
Audits and Self-Assessments
80113264, 2015 Focused Area Self-Assessment to Determine Readiness for NRC Component
Design Basis Inspection (CDBI), dated 3/20/15
Calculations
1EA-HV-2198C, AC Motor Operated GL96-05 Butterfly Valve, Revision 7 1EA-HV-2198D, AC
Motor Operated GL96-05 Butterfly Valve, Revision 4
12-0150, Suppression Pool Water Level Limitation for ECCS Pump Operation during Plant
Shutdown, Revision 1
646-8, Equipment Foundation, Revision 2 1108-0064-CLC-01, Differential Pressure across Hope
Creek Service Water Pump Discharge Valve 1EA-HV-2198C, Revision 0
1108-1407-0064, Differential Pressure across Hope Creek Service Water Pump Discharge Valve
1EA-HV-2198C, Revision 0
E-1.4, HC Class 1E 125 & 250VDC Systems: Short Circuit & Voltage Drop Studies, Revision 6
E-4.1, HC Class 1E 125 VDC Station Battery & Charger Sizing, Revision 17
E-4.2, Hope Creek Generating Station Class 1E DC Equipment & Component Voltage Study,
Revision 5
E-4.6, Hope Creek 125 VDC Beyond Design Basis Event Battery Sizing Calculation, Revision 0
E-5.1, HC Class 1E 250 VDC Station Battery & Charger Sizing, Revision 8
E-6.1, Non-Class 1E 250 & 125 VDC Station Battery and Charger Sizing, Revision 12
E-7.4, Class 1E 4.kV System Protective Relay Settings, Revision 6
E-7.9, 125VDC & 250VDC Class 1E System, Revision 4
E-9, Standby Class 1E Diesel Generator Sizing, Revision 9
E-15.1, Hope Creek Load Flow and Degraded Voltage Analysis, Revision 11
E-17B, Voltage Drop for 125 VDC Control Circuit, Revision 0
E-17D, 125 VDC, Voltage Drop from Distribution Panel to Load Panel 1CD417
(Class 1E Channel C), Revision 5
EA-0001, Differential Pressure Calculations, Revision 3
EA-0003, Station Service Water System Hydraulic Analysis, Revision 12
EQ-HC-021A, Environmental Qualification Binder for Limitorque, Motor Operated Valves Model
SMB Series, Revision 1
EQ-HC-021B, Environmental Qualification Binder for Limitorques, Motor Operated Valves Models
SMB Series DC Valve, Revision 1
EQ-HC-021C, Environmental Qualification Binder for Limitorque, Valve Actuator Components,
Revision 1
EQ-HC-028B, Environmental Qualification Binder for Automatic Switch Company (ASCO),
Solenoid Valve Model(s) NP8316 Series, Revision 1
EQ-HC-056A, Environmental Qualification Binder for Tyco Electronics, Control and Timing
Relays, Model(s) E7000 Series, Revision 1
EQ-HC-056B, Environmental Qualification Binder for Tyco Electronics, Control Timing Relays,
Model(s) ETR Series, Revision 1
H-1-BC-MDC-0922 (028), MOV Capability Assessment for 1BC-HV-F021B, Revision 1
H-1-EA-MDC-4010, Elastic - Plastic Finite Element Analysis of Hope Creek Service Water
Strainer Element, Revision 0
H-1-FD-MDC-0941 (002), MOV Capability Assessment for 1FD-HV-F001, Revision 1
H-1-GK-MDC-0735, Electrical Heat Load During the Station Blackout Event, Revision 1
A-3
H-1-JE-IST-6806, Fuel Oil Transfer Pumps Flow Rate, Revision 0
H-1-JE-IST-7510, Fuel Oil Transfer Pumps Suction Pressure, Revision 0
H-1-JE-IST-7513, Fuel Oil Transfer Pumps Discharge Pressure, Revision 0
H-1-KB-MDC-1007, Backup Pneumatic Supply for 1GSHV-4964 and 1GSHV-11541 Valves,
Revision 0
JE-13, Diesel Fuel Oil Day Tank, Revision 7
J-121, Suppression Pool Level Low, Revision 0
MIDACALC Results: 1BC-HV-F021B (HCGS-1) AC Motor Operated GL96-05 Gate Valve,
Revision 4
MIDACALC Results: 1FD-HV-F001 (HCGS-1) DC Motor Operated GL96-05 Gate Valve,
Revision 5
Report No. 879A, Stress Analysis Calculation of 28 Inch Model 596 Strain-O-Matic Strainer,
Revision 3
SC-JE-0059, Diesel Fuel Day Tank Level, Revision 7
XX-C-008, Drawing of Graphs to Show Contents of Tanks at all Levels, Revision 1
Completed Surveillance, Performance, and Functional Tests
HC.MD-ST.GS-0001, Torus to Drywell Vacuum Relief Valve 18 Month Testing, performed 11/4/13
HC.MD-ST.PK-0001, 125 Volt Weekly Battery Surveillance, performed 8/10/15
HC.MD-ST.PK-0002, 125 Volt Quarterly Battery Surveillance, performed 4/28/15 and 8/8/15
HC.MD-ST.PK-0006, 125 Volt Station Batteries Performance Discharge Test using BCT-2000
with Windows Software and Associated Surveillance Testing, performed 11/6/10
HC.MD-ST.PK-0007, 125 Volt Station Batteries 18 Month Service Test using BCT-2000 with
Windows Software and Associated Surveillance Testing, performed 4/29/15
HC.OP-FT.KB-0001, H1KB-10-K-100 Emergency Instrument Air Compressor, performed 8/6/15
HC.OP-IS.BC-0003, BP202, B Residual Heat Removal Pump In-Service Test, performed
10/14/15
HC.OP-IS.BC-0102, Residual Heat Removal Subsystem B Valves - In-Service Test, performed
11/2/13
HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - OP204 and OP217 - In-Service Test,
performed 9/21/15
HC.OP-IS.EA-0101, Service Water Subsystem A Valves - In-Service Test, performed 7/4/15 &
10/9/15
HC.OP-IS.EG-0101, Safety Auxiliaries Cooling System - Subsystem A Valves - In-Service Test,
performed 4/2/15, 7/19/15, & 10/8/15
HC.OP-IS.EG-0102, Safety Auxiliaries Cooling System - Subsystem B Valves - In-Service Test,
performed 5/21/15 & 8/21/15
HC.OP-IS.JE-0008, H Diesel Fuel Oil Transfer Pump-HP401 - In-Service Test, performed 7/6/15
HP.OP-LR.BC-0203, Containment Isolation Valve Type C Leak Rate Test: CIVS 1BCHV-F021B,
Penetration P24A: B Drywell Spray, performed 11/2/13
HC.OP-ST.BC-0001, RHR System Piping and Flow Path Verification - Monthly, performed
10/14/15
HC.OP-ST.BC-0004, LPCI Subsystem C ECCS Time Response Functional Test - 18 months,
performed 1/29/14
HC.OP-ST.BC-0005, LPCI Subsystem C ECCS Time Response Functional Test - 18 months,
performed 6/11/14
HC.OP-ST.BC-0006, LPCI Subsystem C ECCS Time Response Functional Test - 18 months,
performed 3/6/14
A-4
HC.OP-ST.BC-0007, LPCI Subsystem C ECCS Time Response Functional Test - 18 months,
performed 9/6/13
HC.OP-ST.BH-0001, SLC Valve Operability Test - Monthly, performed 9/30/15
HC.OP-ST.BJ-0001, HPCI System Piping and Flow Path Verification - Monthly, performed
9/28/15
HC.OP-ST.EG-0001, SACS Flow Path Verification - Monthly, performed 9/27/15
HC.OP-ST.GS-0001, Drywell and Suppression Chamber Oxygen Concentration
Verification - Weekly, performed 10/3/15
HC.OP-ST.GS-0003, Reactor Building/Suppression Chamber Vacuum Breaker Operability
Test - Monthly, performed 10/18/15
HC.OP-ST.GS-0004, Suppression Chamber/Drywell Vacuum Breaker Operability Test - Monthly,
performed 10/19/15
HC.OP-ST.KJ-0002, Emergency Diesel Generator 1BG400 Operability Test - Monthly, performed
10/12/15
HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test - Monthly, performed
6/5/15, 10/6/15
HC.OP-ST.KJ-0004, Emergency Diesel Generator 1DG400 Operability Test - Monthly, performed
10/20/15
HC.OP-ST.KJ-0005, Integrated Emergency Diesel Generator 1AG400 Test - 18 Months,
performed 11/8/10, 6/27/13, & 5/8/15
HC.OP-ST.KJ-0006, Integrated Emergency Diesel Generator 1BG400 Test - 18 Months,
performed 11/5/13 & 4/24/15
HC.OP-ST.KJ-0007, Integrated Emergency Diesel Generator 1CG400 Test - 18 Months,
performed 11/6/13 & 5/4/15
HC.OP-ST.KJ-0008, Integrated Emergency Diesel Generator 1DG400 Test - 18 Months,
performed 11/6/13 & 4/24/15
HC.OP-ST.SV-0001, Remote Shutdown Monitoring Instrumentation Channel Check - Monthly,
performed 8/9/15 & 10/11/15
HC.OP-ST.SV-0002, Remote Shutdown Control Operability - 18 Months RSP Transfer with A
Shutdown Cooling In-Service, performed 4/12/15
HC-OP-ST.ZZ-0006, Drywell to Suppression Chamber Leak Rate Test - 18 Months, performed
4/10/15
Completed Preventive Maintenance, Calibrations, and Inspections
Calibration Report, Crystal XP2 Pressure Gauge Digital 1001-3500 PSIG, dated 3/15/15
HC.IC-CC.BC-0006, RHR-Division 2, Channel E11-N652B Pump Discharge Flow, performed
9/18/10
HC.IC-CC.BJ-0010, HPCI - Division 3 Channel L-48011 Suppression Chamber Level, performed
4/11/14
HC.IC-CC.BJ-0011, HPCI - Division 1 Channel L-4085-1 Suppression Chamber Level,
performed 11/2/14
HC.IC-CC.GS-0009, Containment Atmosphere Control - Division 1 Channel P-4960A1
Suppression Chamber Pressure (Post Accident Monitoring), performed 1/1/15
HC.IC-CC.GS-0010, Containment Atmosphere Control - Division 4 Channel P-4960B1
Suppression Chamber Pressure (Post Accident Monitoring), performed 7/16/15
HC.IC-CC.GS-0014, Containment Atmosphere Control - Division 4 Channel P-4960B3
Suppression Chamber Pressure (Post Accident Monitoring), performed 7/17/15
A-5
HC.IC-CC.SB-0014, RPS - Non Divisional Monitor H1SB-1SBTY-3881B Suppression Pool Bulk
Water Temperature, performed 5/20/14
HC.OP-SO.EA-0001, Service Water System Operation (A/C Pump Swap), performed 10/15/15
Motor Operated Valve PVT Report, dated 6/26/15
OU-AA-335-016, Visual Examination of SACS Expansion Tank 1-EG-1BT-205, performed
11/2/10
RCN-029, Hope Creek H1R18 Torus Project Desludge, Coating Inspection and Repair, Final
SH.MD-EU.ZZ-0009, Motor Power Monitor Data Acquisition for Motor Operated Valves,
performed 4/26/03
S-IR-6H4-0011, Containment Coatings Condition Monitoring Report, Refueling Outage 1R19,
Hope Creek Generating Station, dated 9/21/15
VEN015-003, General Visual Examination Suppression Chamber, dated 4/24/15
VTD 432614, C & D Technologies Battery Inspection Report, dated 8/7/15
Corrective Action Notifications (NOTFs)
20188379
20192357
20249278
20381796
20404688
20442488
20453813
20498861
20503940
20519749
20521256
20555348
20555834
20556952
20558035
20559255
20560095
20563418
20568722
20571913
20573570
20577490
20584759
20584760
20584892
20590426
20593600
20594208
20595574
20597608
20597981
20598216
20598733
20599639
20600422
20605880
20608297
20612199
20613955
20617870
20618872
20619972
20620806
20621955
20625154
20626219
20627235
20627274
20627777
20627787
20628849
20631818
20635146
20641757
20643437
20653020
20653539
20663223
20668283
20670193
20670595
20673076
20680341
20681254
20684134
20684479
20685606
20686862
20687007
20687182
20688379
20688759
20688773
20688828
20689335
20694973
20695961
20696370
20698578
20698782*
20698783*
20698784*
20698785*
20698786*
20698787*
20698788*
20698941
20699521
20701108*
20701119
20702063
20702075
20702283
20702379
20702467
20702491
20702550
20702555
20702588
20702852
20702862
20702863
20702912
20702945
20703138*
20703139*
20703155
20703199
20703218
20703251*
20703257
20703302
20703309*
20703310*
20703343
20703433*
20703449*
20703642
20703728*
20703966
20703967
20704264*
20704347
20704352*
20704464*
20704532*
20704611*
20704622*
20704726*
20704783*
20704862*
20704884
20704910*
20704959*
20705022*
20705352
20705418*
20705420*
20705503*
20705506*
20705507*
20705513*
20705597
20705616*
20705872*
20705873*
20705874*
20705891*
20706542*
20706543*
20706703*
20706707*
20706710*
20706712*
20706717*
20706720*
20706856*
20706857*
20706937*
20706958*
20706937
20707004*
20707031*
20707089*
20707135*
- NOTF written as a result of this inspection
A-6
Design and Licensing Bases
CD-143Y, Diesel Fuel Oil Storage and Transfer System Operation Commitment Document,
dated 6/7/85
CD-392X, Diesel Fuel Oil Storage and Transfer System Operation Commitment Document,
dated 6/7/85
D3.35, Design, Installation and Test Specification for Residual Heat Removal System for the
Hope Creek Generating Station, Revision 9
D7.5, Hope Creek Generating Station Environmental Design Criteria, Revision 22
DE-CB.BC-0036, Configuration Baseline Documentation for Residual Heat Removal System,
Hope Creek Generating Station, Revision 1
DE-CB.BJ/FD-0073, Configuration Baseline Documentation for High Pressure Coolant Injection
(HPCI) System, Hope Creek Generating Station, Revision 0
DE-CB.EA/EP-0052, Configuration Baseline Documentation for Station Service Water System,
Revision 2
DE-CB.KJ/PE-0083, Configuration Baseline Documentation Emergency Diesel-Generator
System, Revision 1
DE-CB.NB/PB-0045, Configuration Baseline Documentation for 4KV Auxiliary Power System,
Revision 1
H-1-VAR-MDS-0357, Design Specification for ECCS Suction Strainers, Revision 0
HC.DE-DB.BH-0001, Standby Liquid Control System, Revision 0
HC.DE-DB.KJ-0001, UFSAR Chapter 15 DB/LB System Validations HC EDG System,
Revision 0
HC.DE-PS.ZZ-0041, Hope Creek Station Blackout Program, Revision 3
Hope Creek In-service Testing Program Submittal Interval 3, Revision 8
PN0-E11-4010-0361-(01), Residual Heat Removal System Design Specification, Revision 3
Drawings
10855-E151, 200 Amp 125 VDC Chargers, Revision 39
83916, 28 Inch Model 956 Final Assembly, Revision D
11874141, Tank, 550 Gallons Fuel Oil Day Tank, ASME III, Revision 0
A-0201-0, General Plant Floor Plan, Level 1-Elevation 54-0, Revision 13
A-0202-0, General Plant Floor Plan, Level 1-Elevation 77-0, Revision 20
A-0203-0, General Plant Floor Plan, Level 1-Elevation 102-0, Revision 19
A-0531-0, Separation Criteria Reactor Building Plan- El 54-0, Revision 4
A-0532-0, Separation Criteria Reactor Building Plan- El 77-0, Revision 4
A-0533-0, Separation Criteria Reactor Building Plan- El 102-0, Revision 6
A-0535-0, Separation Criteria Reactor Building Plan-El 1450, Revision 5
A-0541-0, Separation Criteria Auxiliary Building-Control/Diesel El. 54-0, Revision 6
A-0542-0, Separation Criteria Auxiliary Building-Control/Diesel El. 77-0, Revision 9
A-0543-0, Separation Criteria Auxiliary Building-Control/Diesel El. 102-0, Revision 14
A-0544-0, Separation Criteria Auxiliary Building-Control/Diesel El. 117-6, El. 124-0,
El. 130-0, Revision 6
B617-5903, SACS Expansion Tank, dated 8/5/77
C-0399-0, Anchor Bolts Data for Remote generator & Engine Control Panels, Revision 3
DE-CB.BH-0079, Standby Liquid Control Mechanical Boundary, Revision 20
E-0001-0, Single Line Diagram Station, Revision 24
E-0006-1 Sh. 1, Single Line Meter & Relay Diagram 4.16 KV Class 1E Power System,
Revision 11
A-7
E-0008-1, Single Line Meter & Relay Diagram Diesel Generators, Revision 4
E-0009-1 Sh. 1, 125 VDC System - Channels A & C, Revision 25
E-0009-1 Shs. 3 & 5, 125 VDC System, Revisions 28 & 22
E-0009-1 Sh. 4, 125 V DC System Channels C & D, Revision 13
E-0011-1 Sh. 2, 250V DC System - Unit 1, Revision 19
E-0012-1 Shs. 1, 2, 3, 4, & 5, 120V AC Instrumentation & Misc. Systems,
Revisions 15, 30, 29, 8, and 39
E-0208-0 Sh. 3, Electrical Schematic Diagram 4.16KV Circuit Breaker Control Station Service
Water Pump, Revision 10
E-219-0, Electrical Schematic Diagram RHR Pump Seal & Motor BRG. CLG. WTR SPLY. SOL.
VLV ISV-2520B, Sheet 2, Revision 7
E-6234-0 Sh. 10, Electrical Schematic Diagram, Residual Heat Removal System, Containment
Spray (Inboard) Valve (HV-F021A), Revision 5
E-6441-0 Shs. 1 & 2, Electrical Schematic Diagram Class 1E 4.16KV CKT Breaker Control RHR
Pumps. 1DP202, Revisions 6 & 7
E-6443-0, Electrical Schematic Diagram 4.16 KV Circuit Breaker Control RHR Pump IBP202,
Revision 8
I-03511, Strainer Element Assembly, Revision L
I-770912-A, Strain-O-Matic 180º Flow, Revision 5
J-11-0-9, Safety Auxiliaries Cooling-RHR HX BE 205 Outlet Valve/Seal and BRG. CLG. Water
Valve, Revision 9
J105-0 Shs. 8 & 9, Logic Diagram Sequencer Fan Out, Revisions 6 & 5
M-10-1, Service Water, Revision 55
M-11-1 Shs. 1, 2, 3, & 4, Safety Auxiliaries Cooling, Reactor Building, Revisions 32, 42, 31, & 2
M-12-1 Shs. 1 & 2, Safety Auxiliaries Cooling, Auxiliary Building, Sheet 1, Revisions 31 & 1
M-15-0 Sh. 1, Compressed Air System, Sheet 1, Revisions 50 & 51
M-30-1, Sheet 1, Diesel Engine Auxiliary Systems Fuel Oil, Revision 19
M-48-1, Standby Liquid Control, Revision 16
M-48-1-BH-CBD, Standby Liquid Control, Revision 0
M-51-1 Sh. 1, Residual Heat Removal, Revision 47
M-55-1 Sh. 1, High Pressure Coolant Injection, Revision 24
M-56-1 Sh. 1, HPCI Pump Turbine, Revision 16
M-97-0, Intake Structure Building and Equipment Drains PI&D, Revision 7
O-P-EA-01, System Isometric Intake Structure Service Water, Revision 20
O-P-EA-012, Fab Isometric Intake Structure Service Water, Revision 20
PJ810-009 Shs. 1 & 2, Logic Diagram Emergency Load Sequencer Cabinet C, Revisions 7 & 6
PJ810-009 Sh. 3, Logic Diagram Step Timer Cabinet C, Revision 7
PJ810-009 Sh. 4, Logic Diagram Step Timer, Revision 7
PP302Q-0302 Sh. 0, H1/10-900 Flex Wedge Gate Valve, dated 4/26/12
Engineering Evaluations
1EGHV-2457 A&B, Air Operated Valve (AOV) Capability Evaluation, Revision 2
1EGHV-2520 A&B, Air Operated Valve (AOV) Capability Evaluation, Revision 2
10855-D7.3, Appendix E, Separation Review Data Sheet, Reactor Building Room 4218,
Elevation 77, Revision 1
10855-D7.3, Appendix E, Separation Review Data Sheet, Reactor Building Room 4301,
Elevation 102, Revision 1
A-8
317103(15), Maximum Thrust and Seismic Analysis for 10 - Class 900 Carbon Steel Flex
Wedge Gate valve with SMB-1-60 Limitorque Motor Actuator, Revision 2
317103(41)-01, Maximum Thrust and Seismic Analysis for 16 - Class 300 Carbon Steel Flex
Wedge Gate valve with SB-3-100 Limitorque Motor Actuator, Revision 0
70090160, Suppression Pool Level Low Alarm, dated 10/17/08
70102111-50, Determination of Whether the Reactor Building to Torus Vacuum Breaker,
H1GS-1GSPSV-5030, was able to Perform its Design Function as Defined in Tech Specs
and the Maintenance Rule Program, dated 10/15/09
70105023, Slowly Lowering Torus Level, dated 1/5/10
70106957, NRC Information Notice 2010-03, Revision 0
70124352, Functional Failure Cause Determination Evaluation: Suppression Pool Temperature,
dated 7/7/11
70125650 (NOTF 20516551), IST Pump Evaluation, dated 6/29/11
70139234, MOV 1FDHV-F001 Needs Margin Improvement, Revision 0
70158062, OPEX Response: Potential Design Deficiency in Motor-Operated Valve Control
Circuitry, dated 12/19/13
70158101, IST Rebaseline of H1BC-BC-HV-F021A, Revision 0
70162112, Maintenance Rule Functional Failure Cause Determination, BC-HV-021B Seat
Leakage, dated 2/4/14
70163546, Use-As-Is Interim Disposition Technical Evaluation for 1EAHV-2198C Reverse Flow,
Revision 0
70175293, HPCI Steam Admission Valve (FD-F001) Leakby, dated 5/14/15
70176210, Reportability Review for Rising Torus Level Trend (NOTF 20687007), dated 6/1/15
70176533, Valve H1BC-BC-HV-F021A In-service Test Valve Evaluation, Revision 0
70176608, Valve H1BC-BC-HV-F021A High As-found and As-left Open Thrust during Diagnostic
Testing in H1R19 (30138724), Revision 0
70177495-10, Impact of the RF19 As-Found F SRV Setpoint Pressure on the B Main Steam
Line and F SRV Discharge Line, dated 8/27/15
70177495-40, RF19 SRV Setpoint Test Failures Assessment, dated 8/25/15
70178126, HPCI Core Spray Injection Valve Failed to Open during IST (OP-Eval 15-007),
Revision 1
70180794, H1EA-EA-HV-2198C Reverse Flow Direction Evaluation, dated 10/20/15
80065877, Replace GE AKR DC Breakers, Revision 1
80078355, AKR 125 VDC and 250 VDC Breaker Replacement, Revision 0
80083976, Replace Model DC-2000 Trip Unit with Model DC-2000 NQ Trip Unit, Revision 1
80097309, HPCI Valve HV-8278 Replacement, Revision 0
80108793, C SSW Discharge Valve Failed IST Evaluation, dated 3/2/13
80110417, Technical Evaluation of As-Found leakage for Penetration P24A (1BCHV-F021B
exceeding Administrative Limit), Revision 0
80114188, Multiple Pieces of Tape Discovered in H T-quencher Piping Support Guide Lugs,
Weldsand Dampeners, dated 5/20/15
DEH 110079, Walkdown Information for IER 11-1 Recommendation 3, Capability to Mitigate
Internal and External Flooding Events, Revision 0
DEH 120195, SACS Expansion Tank Level Swings, Revision 1
DEH 120280, STACS Expansion Tanks Sluicing, Revision 10
EQ-HC-072A, Environmental Qualification Binder for Cutler-Hammer INC (EATON), Class 1E,
480V MCC, Reactor Area, Revision 0
A-9
H-1-BB-MEE-1168, Determination of Drywell Insulation Material Debris Sources and Quantities
Generated Due to Postulated High Energy Pipe Breaks, Revision 2
H-1-ZZ-MEE-0864, Motor Operated Gate Valve Pressure Locking/Thermal Binding Review,
Revision 0
HC15-008, Adverse Condition Monitoring and Contingency Plan: HPCI Steam Admission Valve
(FD-F001) Leakby, Revision 3
Orders (Evaluations): 70056192, 70059015, 70060868, 70111202, 70115714, 70128893,
70134962, 70138725, 70139229, 70141532, 70150554, 70158231, 70159261, 70162113,
70163046, 70173642, 80104106, 80108793, 80108856, 80112286
TCCP 4HT-14-028, Defeat High Flow Switch 1KBFSH-7618 for Air Dryer 10F104, Revision 0
Maintenance Work Orders
30013826
30040357
30077629
30087884
30119900
30123531
30138724
30148196
30148488
30157118
30158854
30165813
30174260
30179032
30179104
30190587
30200706
30208969
30218556
30221175
30227181
30234076
30264028
30265252
30272880
60015966
60022564
60079674
60084133
60106988
60107486
60107487
60107488
60109690
60109691
60112463
60121909
60122197
Miscellaneous
Hope Creek Generating Station LER 96-001-00, Safety and Auxiliaries Cooling Systems Heat
Exchangers Fouled with Grass Due to a Failed Service Water Strainer, dated 2/15/96
Hope Creek Generating Station LER 97-021-00, dated 9/22/97
Hope Creek Generating Station LER 97-027-00, Technical Specification Surveillance
Requirement Implementation Deficiencies - 125/250 VDC Batteries, dated 12/15/97
Hope Creek Generating Station LER 98-007-00, dated 11/9/98
Hope Creek Generating Station LER 99-007-00, License Condition Violation - Class 1E Battery
Charging, dated 7/19/99
Hope Creek MOV Program Basis Document, Revision 0
In-Service Testing Scoping Basis, H1BC -BC-HV-F021B, Revision 3.8
In-Service Testing Scoping Basis, H1FD -FD-HV-F001, Revision 3.12
OP-SH-111-101-1001, Hope Creek Narrative Log, dated 10/25/13 - 10/30/13 and 4/28/15 -
5/2/15
QCIR No. 1-CC-428-1-C-1.55, Installation and Testing of Undercut Anchors Inspection record,
dated 9/4/84
Regulatory Guide 1.97, Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess
Plant and Environs Conditions During and Following an Accident, Revision 2
WCDs: 4381567, 4382795
Normal and Special (Abnormal) Operations Procedures
HC.OP-AB.COMP-0001, Instrument and/or Service Air, Revision 6
HC.OP-AB.COOL-0002, Safety/Turbine Auxiliaries Cooling System, Revision 8
HC.OP-AB-ZZ-0024, CRIDS Computer Points Book 5 D3624 thru D4288, Revision 11
HC.OP-AB-ZZ-0025, CRIDS Computer Points Book 6 D4303 thru D4596, Revision 10
HC.OP-AB.ZZ-0149, 250 VDC System Malfunction, Revision 4
HC.OP-AB.ZZ-0150, 125 VDC Malfunction, Revision 7
A-10
HC.OP-AB.ZZ-0172, Loss of 4.16KV Bus 10A403, Revision 7
HC.OP-IO.ZZ-0008, Shutdown from Outside Control Room, Revision 34
HC.OP-SO.BC-0001, Residual Heat Removal System Operation, Revision 53
HC.OP-SO.BJ-0001, High Pressure Coolant Injection System Operation, Revision 48
HC.OP-SO.EE-0001, Torus Water Cleanup System Operation, Revision 14
HC.OP-SO.JE-0001, Diesel Fuel Oil Storage and Transfer System Operation, Revision 32
HC.OP-SO.KB-0001, Instrument Air System Operation, Revision 23
HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 72
HC.OP-SO.PB-0001, 4.16KV System Operation, Revision 29
HC.OP-SO.PJ-0001, 250 VDC Electrical Distribution System Operation, Revision 9
HC.OP-SO.PK-0001, 125 VDC Electrical Distribution System Operation, Revision 24
Operating Experience
10CFR Part 21 Interim Reporting of Tricentric Triple Offset Butterfly Valves, dated 2/7/14
NRC Information Notice 85-20: Motor-operated Valve Failures Due to Hammering Effect, dated
3/12/85
NRC Information Notice 92-26: Pressure Locking Of Motor-Operated Flexible Wedge Gate
Valves, dated 4/2/92
NRC Information Notice 93-98: Motor Brakes on Valve Actuator Motors, dated 12/20/93
NRC Information Notice 2010-03: Failures of Motor-Operated Valves Due to Degraded Stem
Lubricant, dated 2/3/10
NRC Information Notice 2011-12, Reactor Trips Resulting from Water Intrusion into Electrical
Equipment, dated 6/16/11
NRC Information Notice 2012-03: Design Vulnerability in Electric Power System, dated 3/1/12
NRC Information Notice 2013-05: Battery Expected Life and Its Potential Impact on Surveillance
Requirements, dated 3/19/13
NRC Information Notice 2013-14: Potential Design Deficiency in Motor-Operated Valve Control
Circuitry, dated 8/23/13
NRC Information Notice 2013-17: Significant Plant Transient Induced by Safety-Related Direct
Current Bus Maintenance at Power, dated 9/6/13
Weir Valves & Controls USA Letter to PSEG, 28 - 150 Tricentric (EA-HV-2198C) Part 21
Concern, dated 10/26/15
Procedures
CC-AA-11, Nonconforming Materials, Parts, or Components, Revision 5
ER-AA-300, Motor Operated Valve Program Administrative Procedure, Revision 4
ER-AA-302-1003, MOV Margin Analysis and Periodic Verification Test Intervals, Revision 6
ER-AA-302-1008, MOV Diagnostic Test Preparation Instructions, Revision 8
ER-HC-310-1009, Hope Creek System Function Level Maintenance Rule Scoping, Revision 7
ER-SH-330-0009, PSEG Nuclear Repair Program Manual for the Control of R and NR
Certificates of Authorization, Revision 7
HC.IC-CC.BE-0012, Core Spray Division 1 Channels E21A-K22A and E21A and K21A Pump
Start Delay - Normal and Emergency Power, Revision 10
HC.IC-CC.BE-0013, Core Spray Division 2 Channels E21A-K22B and E21A and K21B Pump
Start Delay - Normal and Emergency Power, Revision 10
A-11
HC.IC-CC.BE-0014, Core Spray Division 3 Channels E21A-K22C and E21A and K21C Pump
Start Delay - Normal and Emergency Power, Revision 11
HC.IC-CC.BE-0015, Core Spray Division 4 Channels E21A-K22D and E21A and K21D Pump
Start Delay - Normal and Emergency Power, Revision 9
HC.IC-CC.BJ-0010, HPCI - Division 3 Channel L-48011 Suppression Chamber Level, Revision 8
HC.IC-CC.BJ-0011, HPCI - Division 1 Channel L-4085-1 Suppression Chamber Level,
Revision 10
HC.IC-CC.GS-0005, Containment Atmosphere Control - Division 1, Channel PD-5029,
Reactor Building to Suppression Chamber Pressure Relief (Inboard Isolation Valve Control),
Revision 9
HC.IC-CC.GS-0006, Containment Atmosphere Control - Division 2, Channel PD-5031, Reactor
Building to Suppression Chamber Pressure Relief (Inboard Isolation Valve Control),
Revision 7
HC.IC-CC.GS-0007, Containment Atmosphere Control - Division 1, Channel PD-5029,
Containment/Reactor Building Differential Pressure, Revision 11
HC.IC-CC.GS-0009, Containment Atmosphere Control - Division 2, Channel PD-5031,
Containment/Reactor Building Differential Pressure, Revision 10
HC.IC-CC.GS-0009, Containment Atmosphere Control - Division 1 Channel P-4960A1
Suppression Chamber Pressure (Post Accident Monitoring), Revision 8
HC.IC-CC.GS-0010, Containment Atmosphere Control - Division 4 Channel P-4960B1
Suppression Chamber Pressure (Post Accident Monitoring), Revision 8
HC.IC-CC.GS-0014, Containment Atmosphere Control - Division 4 Channel P-4960B3
Suppression Chamber Pressure (Post Accident Monitoring), Revision 9
HC.IC-CC.SB-0014, RPS - Non Divisional Monitor H1SB-1SBTY-3881B Suppression Pool Bulk
Water Temperature, Revision 21
HC.IC-DC.ZZ-0064, General Electric Ammeters and Voltmeters, Types AB and DB; and
Westinghouse Ammeters and Voltmeters, Type KX-241, KA-241 and KC-241, Revision 9
HC.IC-FT.PE-0003, Emergency Load Sequencer System, Revision 7
HC.IC-FT.PE-0007, Time Interval Test, Revision 8
HC.IC-SC.BJ-0011, HPCI - Division 1 Channel H1BJ-1BJLT-4805-1 Suppression Chamber
Water Level, Revision 13
HC.IC-SC.GS-0001, Containment Atmosphere Control - Division 1 Channel P-4960A1
Suppression Chamber, Revision 8
HC.IC-SC.GS-0002, Containment Atmosphere Control - Division 4 Channel P-4960B1
Suppression Chamber (Accident Monitoring), Revision 7
HC.IC-SC.GS-0003, Containment Atmosphere Control - Division 1 Channel P-4960A2 Drywell
Pressure (Accident Monitoring), Revision 5
HC.IC-SC.GS-0004, Containment Atmosphere Control - Division 4 Channel P-4960B2 Drywell
Pressure (Accident Monitoring), Revision 5
HC.IC-SC.GS-0005, Sensor Calibration Containment Atmosphere Control - Division 1 Channel
P-4960A3 Drywell Pressure, Revision 5
HC.MD-GP.ZZ.0113, Maintenance of Anchor Darling Flexible Wedge Type Gate Valves,
Revision 3
HC.MD-PM.ZZ-0006, General Preventive Maintenance for Distribution Panels, MCCs, Unit
Substations, and Switchgear, Revision 20
HC.MD-ST.GS-0001, Torus to Drywell Vacuum Relief Valve 18 Month Testing, Revision 14
HC.MD-ST.GS-0002, Reactor Building to Torus Vacuum Relief Valve 18 Month Testing,
Revision 12
A-12
HC.MD-ST.PJ-0002, 250 Volt Quarterly Battery Surveillance, Revision 32
HC.MD-ST.PK-0001, 125 Volt Weekly Battery Surveillance, Revision 29
HC.MD-ST.ZZ-0009, Motor Operated Valve Thermal Overload Protection Surveillance,
Revision 21
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 150
HC.OP-IS.BC-0102, Residual Heat Removal Subsystem B Valves - In-service Test, Revision 43
HC.OP-IS.BH-0003, Standby Liquid Control Pump-AP208 - In-Service Test, Revision 16
HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - OP204 and OP217 - In-service Test,
Revision 63
HC.OP-IS.GS-0101, Containment Atmosphere Control System Valves - In-Service Test,
Revision 49
HC.OP-IS.JE-0001, A Diesel Fuel Oil Transfer Pump - AP401 - In-Service Test, Revision 33
HP.OP-LR.BC-0203, Containment Isolation Valve Type C Leak Rate Test: CIVS 1BCHV-F021B,
Penetration P24A: B Drywell Spray, Revision 1
HC.OP-ST.BC-0004, LPCI Subsystem A ECCS Time Response Functional Test - 18 months,
Revision 15
HC.OP-ST.BC-0005, LPCI Subsystem B ECCS Time Response Functional Test - 18 months,
Revision 16
HC.OP-ST.BC-0006, LPCI Subsystem C ECCS Time Response Functional Test - 18 months,
Revision 14
HC.OP-ST.GS-0003, Reactor Building/Suppression Chamber Vacuum Breaker Operability Test -
Monthly, Revision 8
HC.OP-ST.GS-0004, Suppression Chamber/Drywell Vacuum Breaker Operability Test - Monthly,
Revision 13
HC.OP-ST.KJ-0005, Integrated Emergency Diesel Generator 1AG400 Test - 18 Months,
Revision 42
HC.OP-ST.KJ-0007, Integrated Emergency Diesel Generator 1CG400 Test - 18 months,
Revision 46
HP.OP-ST.SV-0001, Remote shutdown Monitoring Instrumentation Channel Check - Monthly,
Revision 26
HC.OP-ST.ZZ-0006, Drywell to Suppression Chamber Leak Rate Test - 18 Months, Revision 17
LS-AA-120, Issue Identification and Screening Process, Revision 13
LS-AA-125, Corrective Action Program, Revision 20
LS-HC-1000-1001, Hope Creek Generating Station, Surveillance Frequency Control Program,
List of Surveillance Frequencies, Revision 6
MA-AA-716-210-1001, Performance Centered Maintenance (PCM) Templates, Revision 12
MA-AA-723-300, Diagnostic Testing and Inspection of Motor Operated Valves, Revision 10
MA-AA-723-300-1005, Review and Evaluation of Motor Operated Valve Test Data, Revision 4
MA-AA-723-301, Periodic Inspection of Limitorque Model SMB/SB/SBD-000 through 5 Motor
Operated Valves, Revision 9
MA-AA-724-113, Meggering of Electrical Equipment (Non-Rotating), Revision 7
OP-AA-108-115, Operability Determinations & Functionality Assessments, Revision 4
OP-AA-108-115-1001, Operability Assessment and Equipment Control Program, Revision 30
OP-AA-111-1001, Severe Weather and Natural Disaster Guidelines, Revision 12
SH.MD-GP.ZZ-0242, Limitorque Valve Actuator Removal and Installation, Revision 6
A-13
Risk and Margin Management
CC-HC-102-1001, Control of Time Critical Operator Actions, Revision 2
H-13-0092, MOV 1FDHV-F001 Margin Improvement, dated 9/17/15
Hope Creek Generating Station Individual Plant Examination, April 1994
Hope Creek Generating Station Individual Plant Examination for External Events, July 1997
Risk-Informed Inspection Notebook for Hope Creek Generating Station, Revision 2.1a
System Health Reports, System Walkdowns, & Trending
4.16 KV AC (Class 1E & Non-1E) System Health Report, Q2-2015
125 VDC (Class 1E) System Health Report, Q2-2015
2014 Breakers Component Health Report, dated 9/30/14
Air Operated Valve Program Health Report, P2-2015
Battery Replacement Schedule, dated 9/24/15
Equipment Qualification Program Health Report, P2-2015
Generic Letter 89-13 (Safety Related Service Water System) Program Health Report, P2-2015
HPCI System Health Report, Q2-2015
In-Service Testing Program Health Report, P2-2015
Instrument Air System Health Report, Q2-2015 & Q1-2015
Motor Operated Valve Program Health Report, P2-2015
RHR System Health Report, Q2-2015
SACS A Loop Expansion Tank Level Trend Data, dated 10/9/12 to 7/14/15
SACS B Loop Expansion Tank Level Trend Data, dated 10/9/12 to 7/14/15
SACS System Health Report, Q2-2015 & Q1-2015
Service Water System Health Report, Q2-2015
Vendor Technical Manuals & Specifications
10SA-A092, Recommended Spare Parts, Revision 0
10855-P-303, Technical Specification for Nuclear Service Steel Gate, Globe, and Check Valves,
2 and Smaller, Revision 5
10855-M707-22-1, Expansion Tanks & Accumulators, Seismic Category 1, B617-9907,
Surface Preparation and Painting-Carbon Steel Vessels, dated 11/23/77
10855 Specification M-70763, Appendix I, SACS Expansion Tank
309448, Standby Battery Vented Cell Installation and Operating Instructions, Revision 9
313628, Maintenance Manual for Flexible Wedge Type Gate Valves, Revision 2
322440, Hayward Tyler Inc. Doc. No. 01-000-077, Revision 1
322441, Hayward Tyler Inc. Doc. No. 01-000-078, Revision 1
322442, Hayward Tyler Inc. Doc. No. 01-000-079, Revision 1
322443, Hayward Tyler Inc. Doc. No. 01-000-083, Revision 1
323981, Atwood and Morrill Instruction Manual for Butterfly Valves, Revision 1
H-1-VAR-MGS-0010 (002) Sheet 40, Valve Data Specification Sheet (1EAV-474), dated 2/28/96
Limitorque SMB-1 Torque Switch Setting Chart, dated 1/1/91
PE051-0014, 250 Volt Chargers Operating Instructions, Revision 4
PE051-0015, General Purpose Relay Series 70, dated 3/1/04
PE109Q-0173, Brown Boveri Electric, Inc., Metal Clad Switchgear, Revision 0
PE112BQ-0002, General Electric Instruction Book GEH 3292C, Revision 11
PE117-0128, Transformer Test Report, Revision 0
PE120Q-0014, Indoor AKD-6 Powermaster SWGR, 06/09/15
PE121Q-0034, IC7700 Motor Control Center 10D251, Revision 8
A-14
PE121Q-0081, Instruction Manual - Motor Control Centers 10D251, 10D261, dated 4/19/99
PJ810Q-0097 Sh. 1, Operation and Maintenance Instructions Emergency Load Sequencer
(ELS), Revision 3
PM-018-0345 Sh. 8, Electrical Schematic Local PT & Exciter Control Panel (1AC420),
Revision 14
PM-018-0366 Sh. 2, Electrical Schematic Engine Control, Revision 12
PM150-0050, Instruction Manual for Model Number LD240-383, Revision 6
PM150AQ-0013, Instruction Manual for Model Number LD240-447, Revision 7
PN0-E21-4010-0007-(01), Core Spray System Design Specification Data Sheet, dated 2/15/90
PN1E11C0020047, Ingersoll-Rand Company Pump 34APKD-4 Curve N760, Revision 0
PP303AQ-0305, Type SMB Instruction & Maintenance Manual, Revision 4
LIST OF ACRONYMS
Agencywide Documents Access and Management System
Air-Operated Valve
American Society of Mechanical Engineers
Anticipated Transients Without Scram
Corrective Action Program
Component Design Bases Inspection
CFR
Code of Federal Regulations
Design Basis Document
Direct Current
DP
Differential Pressure
Division of Reactor Safety
EIAC
Emergency Instrument Air Compressor
ELS
Emergency Load Sequencer
Emergency Operating Procedure
Engineered Safety Feature
Fuel Oil Day Tank
Fuel Oil Transfer Pump
Hope Creek Generating Station
High Pressure Coolant Injection
Heat Exchanger
Instrument Air
IMC
Inspection Manual Chapter
IN
Information Notice
IP
Inspection Procedure
In-Service Test
LCO
Limiting Condition for Operation
LER
Licensee Event Report
Loss-of-Coolant Accident
Loss-of-Offsite Power
A-15
Motor Control Center
Motor-Operated Valve
Non-Cited Violation
NOTF
Notification
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
Operating Experience
Publicly Available Records
Preventive Maintenance
Plant Risk Information e-Book
Public Service Enterprise Group
PSID
Pounds Square Inch Differential
Periodic Verification Test
RACS
Reactor Auxiliaries Cooling System
Risk Achievement Worth
RF
Refueling Outage
Risk Reduction Worth
Service Air
SACS
Safety Auxiliaries Cooling System
Significance Determination Process
Standardized Plant Analysis Risk
Surveillance Test
TS
Technical Specification
Updated Final Safety Analysis Report
VDC
Volts, Direct Current
VTD
Vendor Technical Document
WCD
Work Clearance Document