ML040420422
| ML040420422 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 02/11/2004 |
| From: | Meyer G Reactor Projects Branch 3 |
| To: | Richard Anderson Public Service Enterprise Group |
| References | |
| IR-03-006 | |
| Download: ML040420422 (47) | |
See also: IR 05000354/2003006
Text
February 11, 2004
Mr. Roy A. Anderson
Chief Nuclear Officer and President
P. O. Box 236
Hancocks Bridge, NJ 08038
SUBJECT:
HOPE CREEK NUCLEAR GENERATING STATION - NRC INTEGRATED
INSPECTION REPORT 05000354/2003006
Dear Mr. Anderson:
On December 31, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Hope Creek Station. The enclosed integrated inspection report documents
the inspection findings, which were discussed on January 21, 2004 with Mr. Jim Hutton and
other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
This report documents one finding concerning service water system traveling screen
maintenance problems that has potential safety significance greater than very low significance.
This issue did not present an immediate safety concern because the traveling screen was
restored to operability within technical specification requirements. In addition, the report
documents three NRC-identified findings and two self-revealing findings of very low safety
significance (Green). Two of these findings were determined to involve violations of NRC
requirements. However, because of the very low safety significance and because they are
entered into your corrective action program, the NRC is treating these two findings as non-cited
violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. Additionally,
two licensee-identified violations which were determined to be of very low safety significance
are listed in this report. 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 Nuclear
Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with
copies to the Regional Administrator, Region I; the Director, Office of Enforcement, and the
NRC Resident Inspector at Hope Creek Facility.
Since the terrorist attacks on September 11, 2001, the NRC has issued five Orders and several
threat advisories to licensees of commercial power reactors to strengthen licensee capabilities,
improve security force readiness, and enhance access authorization. In addition to applicable
baseline inspections, the NRC issued Temporary Instruction 2515/148, "Inspection of Nuclear
Reactor Safeguards Interim Compensatory Measures," and its subsequent revision, to audit
and inspect licensee implementation of the interim compensatory measures required by order.
Mr. Roy A. Anderson
2
Phase 1 of TI 2515/148 was completed at all commercial nuclear power plants during calendar
year 2002, and the remaining inspection activities for Hope Creek Generating Station are
scheduled for completion in calendar year 2003. The NRC will continue to monitor overall
safeguards and security controls at Hope Creek Generating Station.
In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its
enclosure, and your response (if any) will be available electronically for public inspection in the
NRC Public Document Room or from the Publicly Available Records (PARS) component of
NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Glenn W. Meyer, Chief
Projects Branch 3
Division of Reactor Projects
Docket No:
50-354
License No:
Enclosure:
Inspection Report 05000354/2003006
w/Attachment: Supplemental Information
Mr. Roy A. Anderson
3
cc w/encl:
W. F. Sperry, Director Business Support
J. T. Carlin, Vice President Nuclear Assurance
D. F. Garchow, Vice President, Engineering and Technical Support
S. Mannon, Acting Manager - Licensing
A. C. Bakken, Senior Vice President Site Operations
J. A. Hutton, Hope Creek Plant Manager
R. Kankus, Joint Owner Affairs
J. J. Keenan, Esquire
Consumer Advocate, Office of Consumer Advocate
F. Pompper, Chief of Police and Emergency Management Coordinator
M. Wetterhahn, Esquire
N. Cohen, Coordinator - Unplug Salem Campaign
W. Costanzo, Technical Advisor - Jersey Shore Nuclear Watch
E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance
State of New Jersey
State of Delaware
Mr. Roy A. Anderson
4
Distribution w/encl:
Region I Docket Room (with concurrences)
M. Gray - NRC Resident Inspector
H. Miller, RA
J. Wiggins, DRA
G. Meyer, DRP
S. Barber, DRP
J. Jolicoeur, OEDO
J. Clifford, NRR
DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML040420422.wpd
After declaring this document An Official Agency Record it will be released to the Public.
To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with
attachment/enclosure "N" = No copy
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No:
050000354
License No:
Report No:
Licensee:
Facility:
Hope Creek Nuclear Generating Station
Location:
P.O. Box 236
Hancocks Bridge, NJ 08038
Dates:
September 28, 2003 - December 31, 2003
Inspectors:
M. Gray, Senior Resident Inspector
M. Ferdas, Resident Inspector
F. Bower, Senior Reactor Inspector
S. Barber, Senior Project Engineer
C. Colantoni, Reactor Inspector
J. DAntonio, Operations Engineer
J. Furia, Senior Health Physicist
J. Jang, Senior Health Physicist
S. McCarver, Reactor Inspector
N. McNamara, Emergency Preparedness Specialist
S. Pindale, Senior Reactor Inspector
Approved By:
Glenn W. Meyer, Chief
Projects Branch 3
Division of Reactor Projects
Enclosure
ii
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R04
Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R05
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1R11
Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R12
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R13
Maintenance Risk Assessments and Emergent Work Evaluation . . . . . . . . . . . 9
1R14
Operator Performance During Non-Routine Evolutions and Events . . . . . . . . . 10
1R15
Operability Evaluations
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1R16
Operator Workarounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1R17
Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R19
Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R20
Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
1R22
Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
1R23
Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1EP2
Alert and Notification System (ANS) Testing (71114.02) . . . . . . . . . . . . . . . . . 18
1EP3
Emergency Response Organization (ERO) Augmentation Testing . . . . . . . . . 19
1EP4
Emergency Action Level (EAL) Revision Review (71114.04) . . . . . . . . . . . . . . 19
1EP5
Correction of Emergency Preparedness Weaknesses and Deficiencies . . . . . 20
1EP6
Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
2PS1
Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems
21
2PS2
Radioactive Material Processing and Transportation . . . . . . . . . . . . . . . . . . . . 23
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
4OA3 Event Followup
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4OA7 Licensee-Identified Violations
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF DOCUMENTS REVIEWED
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-8
Enclosure
iii
SUMMARY OF FINDINGS
IR 05000354/2003006; 09/28/2003 - 12/31/2003; Public Service Electric Gas Nuclear LLC,
Hope Creek Generating Station; Licensed Operator Requalification, Maintenance Effectiveness,
Operator Workarounds, Temporary Plant Modifications, Event Followup
The report covered a thirteen-week period of inspection by resident inspectors, and announced
inspections by a regional radiation specialist, emergency preparedness specialist, and two
health physicist inspectors. Two Green non-cited violations (NCVs), three Green findings, and
one unresolved item with potential safety significance greater than Green were identified.
Additionally, two licensee identified Green NCVs were identified. The significance of most
findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual
Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP
does not apply may be Green or be assigned a severity level after NRC management review.
The NRCs program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.
A.
NRC-Identified and Self-Revealing Findings
Cornerstone: Initiating Events
TBD. A self-revealing finding occurred when the A SSWS traveling screen failed
and PSEG determined that improper cutting of a key without procedure guidance
had been a contributing cause. The inspectors identified an additional problem
that contributed to the failure in that applicable maintenance procedures had not
been used to set traveling chain tension and screen level. This performance
issue was determined to have potential safety significance greater than very low
safety significance, based on preliminary risk assessments that considered the
associated pump unavailable while the traveling screen was inoperable.
(Section 1R12)
Green. An inadequate design change and incorrect calibration of an oil control
switch reduced the reliability of the reactor feedwater pumps, such that a second
pump did not remain in operation following the September 19, 2003 electrical
transient. The reactor automatically scrammed on the resulting low reactor level.
A self-revealing finding was identified, which did not involve a violation of
regulatory requirements.
This finding was more than minor, because it affected the equipment
performance attribute of the initiating events cornerstone. The finding is of very
low safety significance, because mitigation systems were available and
operators could have recovered the unavailable equipment. (Section 4OA3.3)
Green. The inspectors identified that incorrect engineering analyses enabled an
operating procedure to contain incorrect, non-conservative limits for shutting
down the reactor when excessive safety relief valve (SRV) leakage exists. The
finding was a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design
Control.
Enclosure
iv
This finding was greater than minor, because it affected the initiating events
cornerstone attribute of procedure adequacy. The inaccurate engineering
analyses could have resulted in PSEG operating an SRV that could have opened
prior to its setpoint being reached, causing a reactor pressure transient. The
finding was of very low safety significance, because it did not increase the
likelihood of a primary or secondary system loss of coolant accident initiator, did
not contribute to a combination of a reactor trip and loss of mitigation equipment
function, and did not increase the likelihood of a fire or internal/external flood.
(Section 1R23)
Cornerstone: Mitigating Systems
Green. The inspectors determined a self-revealing finding regarding ineffective
corrective actions to address an inadvertent feedwater heater isolation
workaround condition that occurred after scrams from full power. The finding did
not involve a violation of regulatory requirements.
This finding was greater than minor, because feedwater system is a mitigating
system and the finding is associated with the design control attribute of the
mitigating systems cornerstone. The finding is of very low risk significance,
because it is a design deficiency confirmed not to result in loss of function.
While manual action was required it has not resulted in loss of feedwater flow.
(Section 1R16)
Green. The inspectors identified a finding on a feedwater system workaround
condition regarding the digital feedwater control system setdown function but
one which did not involve a violation of regulatory requirements.
This finding was greater than minor, because it affected the design control
attribute of the mitigating systems cornerstone. This finding is of very low risk
significance, because it is a design deficiency confirmed not to result in loss of
function. While the setdown setpoint function has not likely operated correctly
since the system was installed, there has not been a loss of feedwater function
due to this problem, and operator training and procedures provide for operating
RFPs in manual mode where the setdown function is not used. (Section 1R16)
Green. The inspectors identified a non-cited violation when PSEG did not
properly reactivate three limited senior reactor operator (LSRO) licenses prior to
their involvement in refueling activities during the April 2003 refueling outage.
This resulted in these individuals supervising fuel handling operations without
being correctly verified as proficient to do so.
This finding was greater than minor, because it resulted in LSROs performing
fuel movement while not in compliance with their license conditions regarding
reactivation. This finding is of very low safety significance, because it is
administrative in nature and the operators were otherwise current in
requalification. (Section 1R11)
Enclosure
v
B.
Licensee Identified Violations
Violations of very low safety significance, which were identified by PSEG, have been
reviewed by the inspectors. Corrective actions taken or planned by PSEG have been
entered into PSEGs corrective action program. These violations and corrective actions
are listed in Section 4OA7 of this report.
TS 3.4.2.1, "Safety/Relief Valves," requires that 13 of the 14 SRVs open within a
lift setpoint of +/- 3 percent of the specified code safety valve function lift setting.
Contrary to this requirement, PSEG identified that 8 of 14 SRVs experienced
setpoint drift outside of the TS limit. PSEG entered this issue into their corrective
action program as notification 20143634. This finding is of very low safety
significance, because the SRVs would have functioned to prevent a reactor
vessel over-pressurization.
TS 6.12.1 requires that areas having radiation dose rates in excess of 100
millirem per hour be posted, barricaded and access controlled as high radiation
areas. On December 16, 2003, PSEG determined that the radiation levels in the
waste filter holding pump room were 600 millirem per hour, but the room was not
posted or controlled as a high radiation area, nor was the area barricaded. This
event is documented as notification 20170646. This finding is of very low safety
significance, because it did not involve a locked high or very high radiation area
or personnel over-exposure.
Enclosure
REPORT DETAILS
Summary of Plant Status
The Hope Creek Generating Station (HCGS) started the inspection period at 46% power.
Operators were returning the plant to full power following an automatic shutdown (scram) on
September 19 due to a 500 kv electrical fault. Full power was reached on October 3. On
October 4 operators manually scrammed the reactor in accordance with procedures because of
an electro hydraulic control (EHC) system oil leak. The EHC oil was found to be leaking from
the #4 combined intermediate control valve (CIV). After repairing the leak the plant was
returned to full power on October 13.
On October 29 operators reduced power to 80% due to solar magnetic disturbances (SMD) in
accordance with plant procedures. The plant was returned to 100% power on November 1. On
November 15 operators reduced power to 80% for scheduled maintenance on the A reactor
feedwater pump turbine and A feedwater heater string, and to perform a design change to
install a new 500KV breaker. Power was reduced further to 69% when a marsh fire was
identified that approached the 500 KV 5015 transmission line. The transmission line was
removed from service and the design change was not performed. The plant was returned to
100% power on November 18.
On December 5 operators reduced power in order to perform scheduled maintenance on the C
reactor feedwater pump and to repair a steam seal evaporator supply line that was leaking. As
power was reduced personnel identified a reactor water cleanup (RWCU) system flanged joint
leak. The reactor was shutdown and the leaks were repaired. Following repairs operators
established reactor criticality on December 15, entered mode 1 on December 18 and
synchronized the main generator to the grid on December 19. The plant reached full power on
December 23. The plant operated at or near full power for the duration of the inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04
Equipment Alignment (71111.04)
a.
Inspection Scope
The inspectors performed five partial equipment alignment inspections. The partial
alignment inspections were completed on the station service water system (SSWS),
emergency diesel generator (EDG), spent fuel pool cooling system, technical support
center (TSC) chiller, and safety auxiliaries cooling system (SACS) during planned
maintenance that affected redundant equipment trains. The inspectors reviewed
applicable documents associated with equipment alignments as listed in the
Supplemental Information report section. The inspectors reviewed notification
20165973 documenting an equipment alignment problem.
2
Enclosure
Partial System Walkdowns.
PSEG installed a temporary modification 02-002 to support SSWS strainer backwash
manual isolation valve replacement on each train from October 21 through October 24.
The inspectors reviewed SSWS equipment line-up documents and walked down
portions of the SSWS to verify the pumps and a sample of valves were correctly aligned
and maintained.
On October 29 the inspectors reviewed fuel pool cooling system drawings and walked
down system control room indications while the B fuel pool cooling pump was out of
service for maintenance to verify proper system alignment .
From November 8 through November 10 PSEG cross connected the A and C EDG
starting air subsystems. This was due to a lifting relief valve on the C EDG starting air
compressor. The inspectors reviewed the applicable EDG equipment alignment
procedure and walked down portions of the A and C EDG starting air subsystem to
verify that they were correctly aligned and maintained to ensure the A and C EDG air
receivers remained operable.
The A SACS pump was removed from service for scheduled maintenance on
November 19. The inspectors verified the operability of the C SACS pump by verifying
the flowpath was aligned in accordance with its operating procedure. The inspectors
performed walkdowns of the SACS system and observed control room indications.
The B TSC Chiller was removed from service for scheduled maintenance from
November 23 through November 25. The inspectors verified the operability of the A
TSC chiller during this time period. The inspectors verified that the position of valves,
switches, and operating fluid levels for the A TSC chiller were in accordance with the
operating procedure. The inspector also verified proper equipment alignment by
observing control room indications for the TSC chillers.
b.
Findings
No findings of significance were identified.
1R05
Fire Protection (71111.05)
a.
Inspection Scope
The inspectors observed one fire drill and performed eight plant walkdowns. The
inspectors observed a fire drill on November 18 to determine the readiness of the fire
brigade to prevent and respond to fires. The drill scenario involved a simulated
electrical fire in a 125V DC battery charger. During plant walkdowns the inspectors
observed combustible material control, fire detection and suppression equipment
availability, and compensatory measures. The inspectors reviewed Hope Creeks
Individual Plant Examination for External Events (IPEEE) for risk insights and design
features credited in these areas. Additionally, the inspectors reviewed notifications
3
Enclosure
documenting fire protection deficiencies to verify identified problems were being
evaluated and corrected (20168653 and 20168918). The following plant areas were
inspected:
combined intercept valve room on October 4
standby liquid control room on October 31
air equipment area mezzanine on November 3
reactor recirculation motor generator set rooms on November 14
reactor core isolation cooling (RCIC) instrument room on November 17
drywell walkdown during forced outage on December 10
residual heat removal heat exchanger rooms on December 12
service water intake structure on December 15
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification (71111.11)
a.
Inspection Scope
Requalification Activities Review By Resident Staff
The resident inspectors observed one simulator training scenario to assess operator
performance and training effectiveness. The scenario involved an EDG that was
inoperable due to low lube oil temperature, a loss of offsite power (LOP), and a
subsequent station blackout (loss of all ac power) with a failure of the RCIC and high
pressure coolant injection (HPCI) pumps. The inspectors assessed simulator fidelity
and observed the simulator instructors critique of operator performance. The
inspectors also observed control room activities with emphasis on simulator identified
areas for improvement. Finally, the inspectors reviewed applicable documents
associated with licensed operator requalification as listed in the Supplemental
Information report section.
b.
Findings
No findings of significance were identified.
a.
Inspection Scope
Biennial Review By Regional Specialist
Regional inspectors performed a biennial inspection of licensed operator requalification
by reviewing the 2002 biennial written examination, and the 2002 and 2003 operating
examinations to determine whether these examination materials met the criteria of the
examination standards. The inspectors also observed the administration of partial
operating examinations to three individuals. The full examination was not observed due
4
Enclosure
to mechanical problems with the refueling bridge. The inspectors reviewed the licensee
event report history for events related to licensed operator performance and training.
No events of significance were noted for individual followup.
The inspectors evaluated conformance with operator license conditions by reviewing
attendance records for the most recent year training cycle and license reactivation
records and procedures. One finding was identified for inadequate limited senior reactor
operator (LSRO) license reactivation practices.
The inspectors reviewed final requalification exam results for all operators and crews for
the annual operating testing cycle. This review assessed whether pass rates were
consistent with the guidance of NUREG-1021, Revision 9, Operator Licensing
Examination Standards for Power Reactors and NRC Manual Chapter 0609, Appendix
IProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609, Appendix</br></br>I" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., Operator Requalification Human Performance Significance Determination Process
(SDP).
The inspectors verified the following results:
Crew failure rate on the dynamic simulator examination was less than 20%
(Failure rate was 11%).
Individual failure rate on the comprehensive biennial written exam was less than
20% (Failure rate was 0%).
Individual failure rate on the walk-through job performance measures was less
than 20% (Failure rate was 0%).
More than 75% of the individuals passed all portions of the exam (100% of the
individuals passed all portions of the exam).
The inspectors reviewed Order 70034843 concerning a licensed operator requalification
examination scenario that was determined to be invalid after administration. The reason
for invalidating the scenario was that the expected operator actions in the scenario
guide were not procedurally required. These expected actions were to manually operate
HPCI following loss of an inverter. However, the operators removed HPCI from service
due to loss of instrumentation. As a result the reactor coolant system depressurized
and the operators were not challenged with the prescripted critical tasks to perform
emergency depressurization and recognize a failed SRV. As a result the facility
administered an additional scenario to this crew.
b.
Findings
Introduction. The inspectors identified a Green finding for failure to properly reactivate
LSRO licenses in accordance with regulatory requirements prior to refueling activities for
the refueling outage in April 2003.
5
Enclosure
Description. The inspectors identified three LSRO license holders had not properly
reactivated their licenses prior to supervising refueling activities during the refueling
outage commencing in April 2003. PSEG completed an apparent cause evaluation on
this issue and determined that their procedure describing license reactivation did not
have adequate detail concerning how LSRO licenses should be reactivated.
Regulatory requirements in 10 CFR 55.53(f)(2) require that for reactivation of a senior
reactor operator (SRO) license, license holders must stand one shift in the position to
which the individual will be assigned under the direction of another SRO. For the April
2003 outage, the LSROs stood reactivation watches solely under instruction in the
control room with no time on the refueling floor.
In a frequently asked question (Examination Standard 605) on the NRC operator
licensing web page, the NRC staff stated that the intent of this requirement may be met
with a reactivation program that specifies, in detail, the tasks, activities, and procedures
an LSRO must perform or simulate in order to demonstrate proficiency. This program
must also ensure such activities are completed within a reasonable period of time,
ideally one week, prior to the LSRO supervising such activities. While Hope Creek
LSROs received classroom training in January and February 2003, received training on
refueling bridge modifications conducted on the bridge, and participated in procedure
verification and validation of new refueling bridge procedures, no detailed program was
developed or lesson plan followed for refueling bridge activities.
Analysis. The inspector determined that the failure to properly reactivate LSRO licenses
is a performance deficiency, because the applicable requirements of 10 CFR 55.53(f)(2)
were not met. Traditional enforcement does not apply because the issue did not have
any actual safety consequences or potential for impacting the NRCs regulatory function
and was not the result of any willful violation of NRC requirements or Hope Creek
procedures. This finding is greater than minor, because it is associated with the
procedure quality and human performance attributes of the mitigating systems
cornerstone and affects the cornerstone objective of ensuring reliability and capability of
systems that respond to initiating events (in this instance the licensed operators).
However, the finding was determined to be of very low safety significance (Green) using
the SDP for operator requalification human performance findings. Specifically, the
inspectors determined the performance deficiency was Green and not minor, at block 27
of the SDP because greater than 20% of operator licenses reviewed had the specified
deficiency. This deficiency was of an administrative nature with no evidence of the
LSROs being technically deficient in their qualifications. However, not performing the
under-instruction watch in the position to which assigned was a missed opportunity for
operators to potentially identify proficiency and familiarization problems on the refueling
bridge.
Enforcement. 10 CFR 55.53(f) requires that if a licensee has not been actively
performing licensed functions before resumption of licensed functions, an authorized
representative of the facility shall certify that the licensee has completed a minimum of
40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of shift functions under the direction of an operator or senior operator as
6
Enclosure
appropriate and in the position to which the individual will be assigned. For senior
operator with licenses limited to fuel handling, one shift must have been completed.
Contrary to the above, three LSRO licensees stood their license reactivation watches in
the control room rather than on the refueling floor as a refueling SRO for the April 2003
Hope Creek refueling outage. However, because this failure to properly reactivate
LSRO licenses is of very low safety significance and has been entered into the
corrective action program in notification 70035178, this violation is being treated as an
NCV, consistent with section VI.A of the NRC Enforcement Policy (NCV 50-354/03-06-
01).
1R12
Maintenance Effectiveness (71111.12)
a.
Inspection Scope
The inspectors reviewed performance monitoring and maintenance activities for two
systems to determine whether PSEG was adequately monitoring equipment
performance to ensure their maintenance activities were effective to maintain the
equipment reliable. The fire protection system and filtration, recirculation and ventilation
(FRVS) systems were reviewed to verify that the systems were being effectively
monitored in accordance with maintenance rule (MR) program requirements. The
inspectors compared documented functional failure determinations and unavailable
hours to those being tracked by PSEG to evaluate the effectiveness of condition
monitoring activities and determine whether performance goals were being met.
Documents reviewed are listed in the Supplemental Information section of this report
and include work orders, corrective action notifications, preventive maintenance tasks,
systems health reports and applicable maintenance expert panel meeting minutes.
Finally, the inspectors completed their review of PSEGs apparent cause evaluation
completed for station service water system (SSWS) traveling screen failures. This issue
was identified as Unresolved Item 354/03-05-02 in NRC Inspection Report 2003-005
dated November 10, 2003. One finding having potential safety significance greater than
very low was identified regarding this issue. Additionally, the inspectors determined the
finding involved problem identification and resolution aspects, because traveling screen
binding problems were not identified when a shear pin failed and the apparent cause
evaluation did not identify likely additional procedure problems with chain tensioning.
b.
Findings
Introduction. A self-revealing finding occurred when the A SSWS traveling screen failed
and PSEG determined that improper cutting of a key without procedure guidance had
been a contributing cause. The inspectors identified an additional problem that had
contributed to the failure, in that applicable maintenance procedures had not been used
to set traveling chain tension and screen level. These performance issues were
determined to have potential safety significance greater than very low significance.
Unresolved item 354/03-05-02 remains open pending completion of the SDP.
7
Enclosure
Description. The A traveling screen headshaft failure on July 1 was previously
described in NRC Inspection Report 354/2003-05, Section 1R12. The failure
necessitated the A screen bay to be dewatered and the A SSWS removed from service
while maintenance was performed. PSEG completed an apparent cause evaluation and
concluded the A SSWS traveling screen failed because the screen headshaft moved
laterally. This had been caused by maintenance personnel who improperly shortened
the drive sprocket key. The key was purchased from the vendor with a part number,
and key trimming was not in the procedure, work instructions or the vendor manual. In
effect, the key shortening represented an unauthorized change to the traveling screens
design.
PSEG identified a contributing cause regarding inadequate chain tensioning of the drive
side carrier chain, because installed load cells used to perform chain tensioning had
repeatability problems. The inspectors identified an additional causal factor due to a
procedure adherence problem. In their review of the procedure and work package used
to replace the screen headshaft in June 2003 (HC.MD-PM.EP-0003(Q) and work order 60037345), the inspectors noted that directions to level the headshaft and tension the
chain were not included. This information was contained in preventive maintenance
procedure HC.MD-PM.EP-0001(Q), which provided specific load cell ranges while
leveling the headshaft. The inspectors also noted the work order package for the
second shaft replacement in July 2003 did not include a completed preventive
maintenance procedure to tension the carrier chains. However, comments under
notification 20150715 indicted the correct procedure had been used. PSEG initiated
notification 20160886 in response to the inspectors observations.
The inspectors further determined that PSEG missed an opportunity to identify traveling
screen binding problems when the A SSWS screen shear pin failed on June 28, two
days prior to the headshaft failure on July 1. Maintenance personnel had replaced the
shear pin and returned the traveling screen to service. However, the cause of the shear
pin failure was not investigated in detail at that time and did not identify developing
binding problems. The inspectors reviewed the traveling screen vendor manual and
applicable PSEG procedures, which described a test shear pin that should be used to
prevent significant damage during testing, adjustments, and periodic screen checks to
detect increased drag and binding problems. Maintenance personnel did not install a
test shear pin and run the traveling screen to help ensure there were not binding
problems prior to returning the traveling screen to service on June 28. PSEG's apparent
cause evaluation provided corrective actions to change procedures to address this
problem.
Finally, the inspectors identified a problem with the preventive maintenance procedure
direction for checking the drive chain tension. Procedure HC.MD-PM.EP-0001(Q) step
5.2.4 checked the drive chain for looseness and specified a minimum of 4 inches of
chain sag. This procedure step directed maintenance personnel to consider removing a
chain link if the sag was sufficient to allow for removal of one link and still maintain 4
inches of chain sag. The vendor manual specified a range of 4 to 8 inches of chain sag.
The inspectors observed the upper bound was not in PSEG's implementing procedure.
The inspectors reviewed previous yearly preventive maintenance packages (work order
8
Enclosure
30063608 and 30046400) and identified instances where the A SSWS traveling screen
was left in service with 20 and 12 inches of drive chain sag without a record of links
being removed. The inspectors concluded that in these instances the drive chain was
loose and indicated wear beyond that recommended as acceptable by the vendor.
However, the inspectors concluded this issue did not likely cause the A traveling screen
failure on July 1, 2003 because of chain maintenance performed in June 2003.
Analysis. The inspectors determined that the issue was more than minor, because it
was associated with the equipment performance attribute of the mitigating systems
cornerstone objective. Specifically, maintenance procedure adherence problems
resulted in increased unavailability of the A SSWS pump when the A SSWS traveling
screen failed and while repairs were completed. This issue also impacted the initiating
events cornerstone objective to limit the likelihood of those events that affect plant
stability and challenge critical safety functions during shutdown and power operations.
The unavailability of one train of SSW increased the likelihood of a loss of service water
(LOSW) event. The inspectors completed an SDP Phase 1 screening of the finding and
determined that a more detailed Phase 2 evaluation was needed to assess the safety
significance.
The SDP Phase 2 evaluation used the loss of service water worksheet and determined
that the finding to potentially be of low to moderate safety significance (White). The
following assumptions were made in the Phase 2 analysis:
The A SSWS pump was unavailable during repairs of its associated traveling
screen.
The A SSWS pump was unavailable for approximately nine days; therefore an
exposure time of 3 to 30 days was used in the analysis.
No operator recovery credit was assumed.
SSWS was considered to be a multi-train normally cross-tied support system.
Therefore the initiating event likelihood was increased by one order of magnitude
for the associated special initiator.
The preliminary results showed the finding represented an increase in risk of greater
than 1E-7 per year for internal initiating events. At the end of the inspection further
information was being assessed to determine the availability of the A SSWS pump with
the traveling screen inoperable but the bay returned to service, and the risk associated
with external events. This information will be used to complete an SDP Phase 3
analysis to confirm the safety significance of the issue.
Enforcement. 10 CFR 50, Appendix B, Criterion V, Instructions Procedures and
Drawings, requires that activities affecting quality be accomplished in accordance with
documented instructions, procedures or drawings, which shall include appropriate
qualitative and quantitative acceptance criteria to ensure that the task can be
accomplished satisfactorily. Contrary to the above, maintenance personnel did not
9
Enclosure
follow their procedures and work order 60037345 instructions by trimming the A SSWS
traveling screen drive sprocket key without procedure guidance. Additionally, PSEG
Procedure HC.MD-PM.EP-0001(Q) provided qualitative and quantitative criteria for
tension screen carrier chains that was not used under the same work order. Pending
determination of the of the findings safety significance, this unresolved item will remain
open. (URI 50-354/03-05-02)
1R13
Maintenance Risk Assessments and Emergent Work Evaluation (71111.13)
a.
Inspection Scope
The inspectors reviewed two on-line risk management evaluations through direct
observation and document reviews for the following configurations:
emergent unavailability of the A EHC pump due to a clogged discharge filter on
November 13
planned unavailability of the service air compressor (00-K-107) due to scheduled
maintenance from November 18 through November 21
The inspectors reviewed the applicable risk evaluations, work schedules and control
room logs for these configurations to verify that concurrent planned and emergent
maintenance and test activities did not adversely affect the plant risk already incurred
with these configurations. PSEGs risk management actions were reviewed during shift
turnover meetings, control room tours, and plant walkdowns. The inspectors also used
PSEGs on-line risk monitor (Equipment Out Of Service workstation) to gain insights into
the risk associated with these plant configurations. Finally, the inspectors reviewed
notifications documenting problems associated with risk assessments and emergent
work evaluations (20163077 and 20166498). Documents reviewed are listed in the
Supplemental Information report section.
b.
Findings
No findings of significance were identified.
1R14
Operator Performance During Non-Routine Evolutions and Events (71111.14)
a.
Inspection Scope
The inspectors evaluated PSEGs performance during two non-routine evolutions to
determine whether the operator responses were consistent with applicable procedures,
training, and PSEGs expectations. The inspectors observed control room activities, and
reviewed control room logs and applicable operating procedures to assess operator
performance. PSEGs evaluations of operator performance were also reviewed. The
inspectors walked down control room displays and portions of plant systems to verify
status of risk significant equipment and interviewed operators and engineers.
Documents reviewed are listed in the Supplemental Information report section.
Operator performance during the following two non-routine evolutions were reviewed:
10
Enclosure
Grid Disturbance Due to Marsh Fire
On November 15, 2003, while performing a power reduction to support planned
maintenance, a marsh fire was reported in the vicinity of 500 kV transmission line 5015.
Control room operators were communicating with the electrical system operator while
actions were being made to remove line 5015 from service. The system operator
provided several orders to the control room operators of varying magnitude to control
500 kV system voltage during the power reduction and impending 5015 line isolation.
Subsequently, it was determined that the system operator guidance was initially
incorrect, and resulted in a higher voltage on the 500 kV switchyard than expected. In
response to accompanying alarms, the control room operators implemented prompt
actions in accordance with response procedures and restored voltage to normal. During
the electrical transient, the system voltage reached a high of 578 kV. PSEG initiated
notification 20166852 and confirmed that operator performance was adequate and plant
equipment was not adversely affected by the transient.
Plant Shutdown Due to Steam Leaks
On December 5 operators reduced power to perform maintenance on the C reactor
feedwater pump and repair a steam leak on a steam seal evaporator steam supply line.
During the course of the power reduction a leak was discovered on the reactor water
cleanup (RWCU) system. A plant shutdown was performed to repair the RWCU system
leak.
b.
Findings
No findings of significance were identified.
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors reviewed five operability determinations for non-conforming conditions
associated with:
control rod insert and withdraw speeds (70033715)
material condition of the A, B, C and D emergency diesel generator (EDG)
exhaust hoods (70034874, 70034875, 70034877, 70034876)
service water pump head tank lube water supply valve (EA-SV-2247A) installed
in the wrong orientation (70035092)
core spray check valve F006A test results (20169632)
B emergency diesel generator (70035290)
The inspectors reviewed the technical adequacy of the operability determinations to
ensure the conclusions were technically justified. The inspectors also walked down
accessible equipment to corroborate the adequacy of the operability determinations.
Additionally, the inspectors reviewed other safety-related equipment deficiencies PSEG
11
Enclosure
identified during this report period and assessed the adequacy of their operability
screens. Notifications and documents reviewed in this regard are listed the
Supplemental Information report section.
b.
Findings
No findings of significance were identified.
1R16
Operator Workarounds (71111.16)
a.
Inspection Scope
The inspectors reviewed one inspection sample regarding the cumulative effects of
operator workaround issues on the reliability, availability and potential for misoperation
of plant equipment. This included reviews of corrective action notifications that tracked
items listed in the Hope Creek operations workaround list and concerns list to ensure
there were not unidentified impacts due to combinations of issues. The inspectors
reviewed operator logs and control room instrument panels to evaluate potential impacts
on the operators ability to implement abnormal or emergency operating procedures.
Additionally, the inspectors reviewed one workaround condition regarding inadvertent
feedwater heater isolation during reactor scrams from full power. This workaround
condition was reviewed in regard to the October 4 reactor scram from full power to
determine whether it adversely affected the functional capability of the feedwater
system. One Green finding was identified. Documents reviewed are listed in the
Supplemental Information report section.
b.
Findings
Feedwater Heater Isolation Workaround
Introduction. The inspectors observed a self-revealing Green finding regarding
ineffective corrective actions to address an inadvertent feedwater heater isolation
workaround condition. The finding did not involve a violation of regulatory requirements.
Description. On October 4 Hope Creek operators manually scrammed the plant due to
an electric hydraulic control (EHC) system oil leak from a combined intercept turbine
valve actuator. After the plant scram the operator monitoring reactor water level tripped
the A and B reactor feedwater pumps (RFPs) in accordance with procedures to reduce
feedwater flow and control reactor level. Within one minute after the scram the reactor
operator observed indications that all the 1st and 2nd stage feedwater heater string
isolation valves were closing. The operator manually opened the common feedwater
heater bypass valve to prevent isolation of all feedwater flow to the reactor vessel due to
low suction pressure. The operator subsequently tripped the C RFP. During this time
reactor water level increased to the Level 8 (54 inches) setpoint and subsequently
dropped to the Level 3 setpoint (12.5 inches). As the operator opened start-up control
valves, a second Level 8 high level condition occurred before the operator maintained
level within the normal band with primary and secondary condensate pumps.
12
Enclosure
Hope Creek management reviewed the plant trip and operator response and concluded
the action to open the feedwater bypass valve delayed the operator from tripping the C
RFP. This was a causal factor in overfeeding the reactor level and reaching the Level 8
setpoint. Further management review found that inadvertent feedwater isolations and
manual operator actions had occurred during prior reactor scrams from full power since
at least November 1998 and that the issue had been evaluated in notification 20103628.
Notification 20103628 described a plant scram in June 2002 where all three strings of
1st and 2nd stage feedwater heaters (FWHs) isolated due to a high water level in the
steam side of the feedwater heaters. The high water level setpoint and automatic
heater isolation were designed to respond to internal heater tubes ruptures. However,
engineering personnel determined that high water level conditions occurred because the
differential pressure between the condenser and the extraction steam supply greatly
decreased after a full power scram or turbine trip. This reduced condensed extraction
steam flow to the condenser and increased feedwater heater level. PSEG had
proposed modification options to correct this condition in April 2003 under order
70025565; however, they were deferred to a future power uprate project.
As a result of the reactor level control challenges on October 4, PSEG management
initiated notification 20161375 to correct this problem in a more timely fashion
independent of the power uprate project. Additionally, procedures were enhanced in the
interim by adding additional direction to the laminated procedure posted at the RFP
console (HC.OP-AB.ZZ-0001, Attachment 14) to highlight and respond to this expected
condition.
The inspectors reviewed order 70025565 and noted that the modification work to correct
this problem had been determined by PSEG to be a system enhancement. However,
the inspectors concluded the modification work was more than an enhancement,
because it resolved a problem that affected feedwater system reliability during post-
scram conditions. Furthermore, the inspectors concluded procedure guidance
contained in abnormal procedure HC.OP-AB.RPV-0004 could have addressed this issue
better by describing the potential isolation of the 1st and 2nd stage FWHs as an
expected plant response from full power scrams rather than a possible abnormal
condition.
Analysis. The inspectors concluded that while PSEG identified the problem, the
corrective action to correct this condition by modification was untimely and the interim
corrective action to address this by procedure was not fully effective. This performance
issue reduced feedwater system reliability after reactor scrams from full power, because
it necessitated manual operator action to open a bypass valve that was a contributing
causal factor to poor control of reactor water level on October 4.
The non-safety feedwater system is a mitigating system, and it provides flow to the
reactor vessel to maintain the core covered and ensure decay heat removal during
normal and plant scram conditions. The problem involved a design deficiency that was
not corrected in a timely manner. The finding is associated with the design control
attribute of the mitigating systems cornerstone and affected the cornerstone objective of
13
Enclosure
equipment reliability. Therefore, the finding is greater than minor. The risk associated
with this finding was assessed by an SDP Phase 1 evaluation and determined to be of
very low risk significance because it is a design deficiency confirmed not to result in loss
of function. While manual action was needed, the loss of feedwater flow or tripping of a
RFP did not result.
Enforcement. The feedwater system is non-safety related and the feedwater heater
isolation on high water level is not described in the safety analysis report. Therefore,
this finding does not involve a violation of NRC requirements. This issue is being
addressed in the PSEG corrective action program via notification 20161375.
(FIN 50-354/03-06-02)
Feedwater Setdown Setpoint
Introduction. A feedwater system workaround condition regarding the digital feedwater
control system setdown function was identified by the inspectors. The finding did not
involve a violation of regulatory requirements.
Description. The inspectors observed the laminated procedure for stabilizing reactor
water level post-scram allowed for either manual and automatic control of RFPs. The
inspectors determined that the digital feedwater control system (DFCS) provided a
setdown setpoint feature to help prevent excessive feedwater make-up by RFPs in
automatic mode after a reactor scram, as level decreased due to steam void collapse.
The setdown setpoint circuit was designed such that ten seconds after reactor water
level lowered to below 12.5 inches (level 3), the reactor level control setpoint would
automatically be setdown from the normal 35 inches to 18 inches level. The setdown
functioned for RFPs in the automatic control mode and not the manual mode.
The inspectors questioned operators about this function and the reason for placing
RFPs in manual on October 4, and some operators questioned the effectiveness of the
setdown circuit to control reactor water level based on their experience. The inspectors
requested that Hope Creek engineering personnel provide the design basis for the
setdown setpoint level and time delay, and determine whether the setdown function
would have operated as intended on October 4 if the RFPs were left in automatic mode.
In response Hope Creek engineers reviewed the reactor water level response from
October 4 and determined the 10 second time delay was too long and would have
prevented the setdown function from operating. This was because reactor water level
was less than the zero level after 10 seconds because of steam void collapse. Since
the level transmitter providing the level signal to the setdown circuit had a span between
zero and 60 inches the DFCS tagged the transmitter input as failed when at 10 seconds
it was below zero and the DFCS logic disregarded the input. Consequently, the
setdown function would not have operated on October 4 if the RFPs were in automatic
control mode. Hope Creek personnel initiated notification 20164378 to evaluate the
problem and develop a modification to correct this condition. The issue was also
tracked as an additional operator workaround condition.
14
Enclosure
Analysis. The inspectors concluded the setdown setpoint time delay had been too long,
such that the feature was not effective following scrams from full power. This problem
forced manual operator action on the feedwater system after reactor scrams from full
power when RFPs were operated in the automatic mode, because the feedwater level
control was not effective and caused operators to control reactor water level manually.
The non-safety feedwater system is a mitigating system and it provides flow to the
reactor vessel to maintain the core covered and ensure decay heat removal during
normal and plant scram conditions. This finding did not affect the likelihood of an
initiating event such as a reactor scram, because the feedwater setpoint setdown
function operates after a reactor scram from full power.
The finding is associated with the design control attribute of the mitigating systems
cornerstone and affected the cornerstone objective of equipment reliability. Therefore,
the finding is greater than minor. The risk associated with this finding was assessed by
an SDP Phase 1 evaluation and determined to be of very low risk significance, because
it is a design deficiency confirmed not to result in loss of function. While the setdown
setpoint function has not likely operated correctly since the DFCS was installed in 1994,
there has not been a loss of feedwater function due to this problem and operator
training and procedures provide for operating RFPs in manual mode.
Enforcement. The feedwater system is non-safety related and the feedwater setdown
setpoint is not described in the safety analysis report. Therefore, this finding does not
involve a violation of NRC requirements. This issue are being addressed in the PSEG
corrective action program via notification 20164378. (FIN 50-354/03-06-03)
1R17
Permanent Plant Modifications (71111.17)
a.
Inspection Scope
The inspectors reviewed the following two design changes installed during the
inspection period:
Addition of oil recovery system to the A control room chiller (80064555)
B EDG IDR relay modification (80060791)
The design bases, licensing bases, modification instructions and post modification
testing of the affected components were reviewed to verify the performance capability of
this equipment was not adversely affected. The inspectors reviewed the applicable
technical specifications for this equipment to ensure that operability requirements and
allowable outage time limits were met. The inspectors also reviewed notifications
documenting deficiencies identified related to permanent plant modifications. The
documents reviewed as part of these inspections are listed in the Supplemental
Information report section.
b.
Findings
No findings of significance were identified.
15
Enclosure
1R19
Post Maintenance Testing (71111.19)
a.
Inspection Scope
The inspectors observed portions of and/or reviewed the results of five post
maintenance tests (PMT) for the following equipment:
reactor core isolation cooling system (RCIC) pump on October 14
C SSW traveling screen on October 20
C EDG on October 21
B spent fuel cooling pump on October 31
C safety auxiliary cooling (SAC) pump on November 19
The inspectors verified that the PMTs were adequate for the scope of the maintenance
performed. The inspectors reviewed notifications documenting deficiencies identified
during PMTs (20163139, 20163498, and 20162546). The inspectors also reviewed
applicable documents associated with PMTs as listed in the Supplemental Information
report section.
b.
Findings
No findings of significance were identified.
1R20
Refueling and Outage Activities (71111.20)
a.
Inspection Scope
Following the December 5 plant shutdown described in Section 1R14, the inspectors
evaluated PSEGs shutdown risk management actions and forced outage configuration
control. The inspectors toured the Hope Creek containment drywell to observe
equipment conditions and drywell cleanliness. Notifications documenting problems
identified during the outage were reviewed to verify the extent of the problem was
identified and corrective actions taken that were required prior to plant startup. The
inspectors monitored portions of reactor heatup, startup activities and power ascension.
The inspectors reviewed the documents and notifications associated with outage
activities as listed in the Supplemental Information report section.
b.
Findings
No findings of significance were identified.
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors observed portions of the following two surveillance tests and reviewed
the results:
16
Enclosure
B EDG on October 27
C/D pump core spray (CS) IST on October 28
The inspectors evaluated the test procedures to verify that applicable system
requirements for operability were adequately incorporated into the procedures and that
test acceptance criteria were consistent with the technical specification requirements
and the updated final safety analysis report (UFSAR). The inspectors also reviewed
notifications documenting deficiencies identified during these surveillance tests.
b.
Findings
No findings of significance were identified.
1R23
Temporary Plant Modifications (71111.23)
a.
Inspection Scope
The inspectors reviewed the following two temporary plant modifications:
Increase the alarm setpoint for tailpipe temperature to 225 oF for safety relief
valve 1ABPSV-F013P (T-Mod 03-041)
Installation of temporary service water strainer backwash discharge piping (T-
Mod 02-002)
The inspectors verified the modifications were consistent with the design and licensing
bases of the affected systems and that the performance capability of these systems
were not degraded by these modifications. The inspectors also reviewed the
modifications to verify applicable technical specification operability requirements were
met during installation. The inspectors verified the modified equipment alignment
through control room instrumentation and plant walkdowns of accessible portions of the
affected equipment. The inspectors further reviewed notifications documenting
problems associated with equipment affected by temporary modifications (20164977).
b.
Findings
Introduction. The inspectors identified that incorrect engineering analyses enabled an
operating procedure to contain incorrect, non-conservative limits for shutting down the
reactor when excessive safety relief valve (SRV) leakage exists. The finding is of very
low safety significance (Green) and a non-cited violation of 10 CFR 50, Appendix B,
Criterion III, Design Control.
Description. During a procedure review related to T-Mod 03-041, the inspectors
identified multiple incorrect, non-conservative temperature limits for elevated SRV
tailpipe temperatures in procedure HC.OP-DL.ZZ-0003, Log 3 Control Console Log
Condition 1, 2 and 3). The limits specify when a plant shutdown should be initiated.
Elevated tailpipe temperature is an indication of SRV pilot leakage, which can cause an
SRV to lift prior to its reactor pressure setpoint being reached.
17
Enclosure
In engineering analyses PSEG determined the limits from vendor test data (steam
temperature as a function of distance from a SRV with a specified SRV leak rate) and
the thermocouple locations for each installed SRV. Given the leak rate which could
cause an inadvertent SRV actuation, PSEG computed the maximum acceptable tail pipe
temperature for each SRV. However, the inspectors determined that some
thermocouple location data was incorrect. When PSEG re-performed the calculation
with correct data, the original limits for seven of the fourteen SRVs (C, E, G, H, K, L, and
P) were incorrect; five of the seven were non-conservative.
Additionally, the inspectors determined that the limits contained in the procedure were
established via an informal analysis and had not been documented as a controlled
calculation. The original thermocouple location data was in a previous engineers file,
and the data had not been verified against design drawings.
Analysis. The performance deficiency was more than minor, because it affected the
initiating events cornerstone attribute of procedure adequacy. The inaccurate
engineering analyses produced SRV tailpipe temperature limits which could have
resulted in PSEG operating an SRV that may open prior to its setpoint being reached,
thus causing a reactor pressure transient. PSEG has reviewed the previous and current
operating cycle SRV tailpipe temperature data and determined the SRV tailpipe
temperatures did not exceed the revised limits. Additionally, PSEGs methodology
included margin such that prior minor leakage did not exceed the tailpipe temperature
limits where SRV reliability would have been impacted.
The inspectors determined that the finding was of very low safety significance (Green)
by the SDP Phase 1 screening worksheet for initiating events, because the finding did
not increase the likelihood of a primary or secondary system loss of coolant accident
initiator, did not contribute to a combination of a reactor trip and loss of mitigation
equipment function, and did not increase the likelihood of a fire or internal/external flood.
Enforcement. 10 CFR Part 50, Appendix B, Criterion III requires that design control
measures shall assure that the design basis is correctly translated into procedures.
Contrary to the above, engineering analyses used incorrect SRV location data which
resulted in multiple incorrect, non-conservative SRV tailpipe temperature limits, which
were included in procedure HC.OP-DL.ZZ-0003 in March 2003. However, because the
violation is of very low safety significance (Green) and PSEG entered the deficiency into
their corrective action system (Notification 20164197), this finding is being treated as a
non-cited violation, consistent with section VI.A. of the NRC Enforcement Policy, issued
May 1, 2000 (65FR25368). (NCV 50-354/03-06-04)
Cornerstone: Emergency Preparedness
1EP2
Alert and Notification System (ANS) Testing (71114.02)
a.
Inspection Scope
18
Enclosure
A regional inspector reviewed PSEGs ANS to ensure prompt notification of the public
for taking protective actions. The inspection included a review of the following
procedures: (1) NC.EP-DG.ZZ-0007(Z), Siren Test Process; and (2) Alert Notification
System Daily Operational Guideline. In addition, the inspector interviewed the siren
program technicians, and reviewed maintenance and 2002/2003 test records to
determine if test failures were being immediately assessed and repaired, and sirens
were being routinely maintained. The inspection was conducted in accordance with
NRC Inspection Procedure 71114, Attachment 02, and the applicable planning standard,
10 CFR 50.47(b)(5) and its related 10 CFR 50, Appendix E requirements were used as
reference criteria.
b.
Findings
No findings of significance were identified.
1EP3
Emergency Response Organization (ERO) Augmentation Testing (71114.03)
a.
Inspection Scope
A regional inspector reviewed the PSEG ERO augmentation staffing requirements and
the process for notifying the ERO to ensure the readiness of key staff for responding to
an event and timely facility activation. The inspector reviewed the 2002/2003
communication pager test records and associated notifications. A review was also
conducted of the backup notification systems that would be used in case of a power
outage. The inspector interviewed the EP training instructor to determine the adequacy
of the lesson plans used for training ERO, which included detailed lesson plans and
lessons learned from past drills for correcting ERO performance problems. Finally, the
emergency plan qualification records for key ERO positions were reviewed to ensure all
EROs qualifications were current. The inspection was conducted in accordance with
NRC Inspection Procedure 71114, Attachment 03, and the applicable planning standard,
10 CFR 50.47(b)(2) and its related 10 CFR 50, Appendix E requirements were used as
reference criteria.
b.
Findings
No findings of significance were identified.
1EP4
Emergency Action Level (EAL) Revision Review (71114.04)
a.
Inspection Scope
A regional in-office review of revisions to PSEGs emergency plan, implementing
procedures and EAL changes was performed for determining that changes had not
decreased the effectiveness of the plan. The revisions covered the period from January
to December 2003. Onsite the regional inspector evaluated the associated 10 CFR 50.54(q) reviews in which PSEG determined that a decrease in effectiveness had not
occurred. The inspection was conducted in accordance with NRC Inspection Procedure
19
Enclosure
71114, Attachment 04, and the applicable requirements in 10 CFR 50.54(q) were used
as reference criteria.
b.
Findings
No findings of significance were identified.
1EP5
Correction of Emergency Preparedness Weaknesses and Deficiencies (71114.05)
a.
Inspection Scope
A regional inspector reviewed corrective actions identified by PSEG pertaining to
findings from 2002/2003 drill/exercise reports and the associated corrective action
notifications to determine the significance of the issues and to determine if repeat
problems were occurring. Also, various quality assurance audit reports from 2002 and
2003 were reviewed to assess PSEGs ability to identify issues, assess repetitive issues
and the effectiveness of corrective actions through their independent audit process. In
addition, the inspector reviewed 2002/2003 self assessment reports to assess PSEGs
ability to be self critical, thus avoiding complacency and degradation of their emergency
preparedness (EP) program. Audit and self assessment reports reviewed are listed in
the Supplemental Information section of this report.
Finally, the inspector reviewed several trending reports generated for tracking various
program activities, ERO qualifications and ERO exercise/drill performance breakdowns.
The reports are an assessment tool used for identifying program problem areas,
management briefings and identifying topics for self assessments. This inspection was
conducted according to NRC Inspection Procedure 71114, Attachment 05, and the
applicable planning standard, 10 CFR 50.47(b)(14) and its related 10 CFR 50, Appendix
E requirements were used as reference criteria.
b.
Findings
No findings of significance were identified.
1EP6
Drill Evaluation (71114.06)
a.
Inspection Scope
The resident inspectors observed two licensed operator requalification scenario exams
on October 16 in the simulator. The scenarios were reviewed prior to the exams to
identify the expected event classification and notification actions. The inspectors
observed the exams and PSEGs post-exam critique of operator performance to verify
that weaknesses and deficiencies were adequately identified. The inspectors
specifically focused on ensuring PSEG identified any operator performance problems
with event classification and notification activities, and ensured the problems were
corrected.
20
Enclosure
b.
Findings
No findings of significance were identified.
21
Enclosure
2.
RADIATION SAFETY
Cornerstone: Public Radiation Safety
2PS1
Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems
(71122.01)
a.
Inspection Scope
The inspectors completed nine inspection samples relative to radioactive gaseous and
liquid effluent treatment and monitoring. The following documents were reviewed to
evaluate the effectiveness of PSEGs radioactive gaseous and liquid effluent control
programs. The requirements of the radioactive effluent controls are specified in the
Technical Specifications/Offsite Dose Calculation Manual (TS/ODCM).
2002 Radiological Annual Effluent Release Report and Radiation Dose
Assessment Report
current ODCM (Revision 20, April 2002) and technical justifications for ODCM
changes
implementation of IE Bulleting 80-10, Contamination of Non-Radioactive System
and Resulting Potential for Unmonitored, Uncontrolled Release of Radioactivity
to environment
selected 2003 analytical results for radioactive liquid, charcoal cartridge,
particulate filter, and noble gas samples
selected 2002-2003 radioactive gaseous and liquid release permits, including
monthly projected public dose assessments
implementation of the compensatory sampling and analysis program when the
effluent radiation monitoring system (RMS) is out of service
trending evaluations of the availability for effluent RMS
calibration records for chemistry laboratory measurements equipment (gamma
and liquid scintillation counters)
implementation of the measurement laboratory quality control (QC) program,
including control charts
implementation of the interlaboratory comparisons by PSEG and the contractor
laboratory
2003 QA Audit (Audit Numbers 2003-0012, 2003-0016, and 2003-0175 ), audit
findings
chemistry self assessment reports (Report Numbers 70028108, Counting Room
Assessment and 80048283-0160, ODCM Implementation)
The inspectors reviewed the most recent channel calibration and channel functional test
results for the radioactive liquid and gaseous effluent radiation monitoring system (RMS)
and its flow measurement devices for those listed in the Tables 4.3.7.10-1 and 4.3.711-1
of the ODCM. Specifically, the following RMS channel and flow monitor calibration
results were reviewed:
22
Enclosure
RMS Channel Calibration
Liquid Radwaste Discharge Line to the Cooling Tower Discharge Line
Turbine Building Circulating Water Dewatering Sump Disacharge Line to the
Cooling Tower Blowdown Effluent
FRVS Noble Gas Activity Monitor
South Plant Vent Noble Gas Activity Monitor
North Plant Vent Noble Gas Activity Monitor
Flow Monitor Calibration
Liquid Radwaste Discharge Line to Cooling Tower Blowdown Line
Cooling Tower Blowdown Weir
Turbine Building Circulating Water Dewatering Sump Discharge Line to the
FRVS Sampler Flow Rate Monitor
FRVS Flow Rate Monitor
South Plant Vent Flow Rate Monitor
South Plant Vent Sampler Flow Rate Monitor
North Plant Vent Flow Rate Monitor
North Plant Vent Sampler Flow Rate Monitor
The inspectors reviewed the most recent surveillance test results (visual inspection,
delta P, in-place testings for HEPA and charcoal filters, air capacity test, and laboratory
test for iodine collection efficiency) for the following air treatment systems:
TS 3/4.7.2
Control Room Emergency Filtration System
TS 3/4.6.5.3
Filtration, Recirculation and Ventilation Systems (FRVS)
UFSAR Commitment Systems: (1) Reactor Building Ventilation Exhaust; (2)
Offgas Exhaust System; (3) Radwaste Exhaust System; and (4) Radwaste Vent
Filter System.
The inspectors toured and observed the following activities to evaluate the effectiveness
of PSEG's radioactive gaseous and liquid effluent control programs.
walkdown for determining the availability of radioactive liquid/gaseous effluent
RMS and for determining the equipment material condition;
walkdown for determining operability of air cleaning systems and for determining
the equipment material condition; and
observed PSEG's radioactive effluent sampling techniques and preparing the
measurement at the laboratory.
The inspectors reviewed Special Report 354/03-006 dated October 1, 2003. The
inspectors also reviewed notifications documenting problems concerning effluent RMS,
air cleaning systems, and routine effluent control programs as listed in the Supplemental
Information section of this report.
23
Enclosure
b.
Findings
No findings of significance were identified.
2PS2
Radioactive Material Processing and Transportation (71122.02)
a.
Inspection Scope
The inspectors completed six samples relative to radioactive material processing and
transportation. The inspectors reviewed the solid radioactive waste system description
in the updated final safety analysis report (UFSAR) and the recent radiological effluent
release report for information on the types and amounts of radioactive waste disposed.
The inspectors reviewed the scope of PSEGs audit program to verify that it meets the
requirements of 10 CFR 20.1101(c).
The inspectors walked-down the liquid and solid radioactive waste processing systems
and determined that the current system configuration and operation agree with the
descriptions contained in the UFSAR and in the Process Control Program (PCP). The
inspectors reviewed the status of any radioactive waste process equipment that is not
operational and/or is abandoned in place. The inspectors verified that the changes were
reviewed and documented in accordance with 10 CFR 50.59 as appropriate. The
inspectors reviewed current processes for transferring radioactive waste resin and
sludge discharges into shipping/disposal containers to determine if appropriate waste
stream mixing and/or sampling procedures, and methodology for waste concentration
averaging provided representative samples of the waste product for the purposes of
waste classification as specified in 10 CFR 61.55 for waste disposal. The
systems/subsystems reviewed included: reactor water clean-up; spent fuel pool clean-
up; floor drain; equipment drain; miscellaneous waste; and, solid waste processing. The
inspectors also toured current and abandoned in-place radwaste equipment and
facilities, and interim storage locations used for processed radwaste. The areas toured
by the inspectors are listed in the Supplemental Information report section.
The inspectors reviewed the radio-chemical sample analysis results for each of PSEGs
radioactive waste streams. The inspectors reviewed PSEGs use of scaling factors and
calculations used to account for difficult-to-measure radionuclides. The inspectors
verified that PSEGs program assures compliance with 10 CFR 61.55 and 10 CFR 61.56
as required by Appendix G of 10 CFR Part 20. The inspectors reviewed PSEGs
program to ensure that the waste stream composition data accounted for changing
operational parameters.
The inspectors previously observed shipment packaging, surveying, labeling, marking,
placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers
provided to the driver, and PSEGs verification of shipment readiness as documented in
NRC Inspection 05000354/2003004. Shipment 03-53 was observed. The inspectors
verified that the requirements of any applicable transport cask Certificate of Compliance
were met. The inspectors verified that the receiving licensee was authorized to receive
the shipment packages. The inspectors observed radiation workers during the conduct
24
Enclosure
of radioactive waste processing and radioactive material shipment preparation activities.
The inspectors determined that the shippers were knowledgeable of the shipping
regulations and that shipping personnel demonstrated adequate skills to accomplish the
package preparation requirements for public transport with respect to NRC Bulletin 79-
19 and 49 CFR Part 172 Subpart H. The inspectors verified that PSEGs training
program provides training to personnel responsible for radioactive waste processing and
radioactive material shipment preparation activities.
The inspectors reviewed 5 non-excepted package shipment (LSA I, II, III, SCO I, II,
Type A, or Type B) records. The inspectors reviewed these records for compliance with
NRC and DOT requirements. Shipments reviewed included: 03-17, 03-18, 03-36, 03-
53, and 03-74. Finally, the inspector reviewed notifications, audits, and self-
assessments related to the radioactive material and transportation programs performed
since the last inspection.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
a.
Inspection Scope
The inspectors reviewed PSEGs program to gather, evaluate and report information on
the following eight performance indicators (PIs). The inspectors used the guidance
provided in NEI 99-02, Revision 2, Regulatory Assessment Performance Indicator
Guideline to assess the accuracy of PSEGs collection and reporting of PI data.
Unplanned Scrams per 7,000 Critical Hours
The inspectors verified the accuracy and completeness of reported manual and
automatic unplanned scrams during the period of July 1, 2002 through September 30,
2003. The inspectors reviewed licensee event reports, corrective action notifications,
monthly operating reports, and PSEG nuclear plant power history charts.
Scrams With Loss of Normal Heat Sink
The inspectors reviewed and verified PSEGs basis for including or excluding an
unplanned manual and automatic reactor scram in the scrams with loss of normal heat
removal PI during the period of July 1, 2002 through September 30, 2003. The
inspectors reviewed operating logs, corrective action notifications, and PSEG nuclear
plant power history charts.
Unplanned Transients per 7,000 Critical Hours
25
Enclosure
The inspectors verified the accuracy and completeness of reported transients that
resulted in unplanned changes and fluctuations in reactor power of greater then 20
percent power during the period of July 1, 2002 through September 30, 2003. The
inspectors reviewed operating logs, corrective action notifications, monthly operating
reports, and PSEG nuclear plant power history charts.
Safety System Unavailability (SSU) Residual Heat Removal System
The inspectors verified the accuracy and completeness of reported unavailability hours
for the RHR system during the period of July 1, 2002 to September 30, 2003. The
inspectors reviewed control room operating logs, corrective action program notifications,
and MR electronic databases.
RETS/ODCM Radiological Effluent Occurrences
The inspectors verified the accuracy and completeness of reported radiological effluent
release occurrences at Hope Creek during the period of June 1, 2002 to September 30,
2003. The inspectors reviewed monthly and quarterly projected liquid and gaseous
effluent releases dose assessment results and corrective action program notifications.
Emergency Preparedness Program
The inspectors reviewed PSEGs procedure for developing the data for the three 2003
emergency preparedness PIs: (1) Drill and Exercise Performance (DEP), (2) ERO Drill
Participation, and (3) alert and notification system (ANS) Reliability. The inspector also
reviewed PSEGs 2003 drill/exercise reports, training records and ANS testing data to
verify the accuracy of the reported data.
b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
1.
Annual Sample Review
a.
Inspection Scope
The inspectors completed one sample review regarding PSEGs evaluation and
resolution of the A EDG intercooler pump mechanical seal leak that occurred in June
2003. This pump seal leak is described in NRC Inspection Report 354/2003004 dated
August 1, 2003, Section 1R12. The root cause evaluation was documented in Order
70032114. The inspectors reviewed the evaluation to determine whether the problem
was identified in timely manner. The inspectors determined whether the evaluation
adequately identified the scope of the problem and considered industry operating
experience. The technical detail and depth of the evaluation were considered to assess
whether the causal factors identified were adequately supported. Finally, the inspectors
26
Enclosure
reviewed the schedule and completion of corrective actions to determine whether the
actions were completed consistent with the safety significance of the problem.
b.
Findings and Observations
The inspectors concluded that the root cause evaluation and corrective actions for the A
EDG intercooler pump mechanical seal leak were adequate. However, the inspectors
also concluded that a more in-depth problem assessment by PSEG engineering
personnel as the leakage developed in 2003 could have provided for more timely
resolution of the problem in June 2003. Additionally, the inspectors observed similar
weakness in PSEGs evaluation of a current EDG lube oil leak.
The inspectors determined the A EDG root cause evaluation adequately identified the
problem by reviewing pump seal maintenance history for each EDG, oil sample trend
information and industry experience. The evaluation methodology was adequate and
used fault tree, and cause and effect analyses to identify the events leading to the pump
intercooler leakage, and time change analysis to evaluate the seal component
performance. During pump disassembly in June 2003, PSEG identified the physical
cause of the intercooler leakage was a seized thrust bearing that allowed excessive
axial pump shaft movement. This caused excessive movement of the intercooler pump
seal faces. The carbon faced pump seal had been shimmed excessively to minimize
leakage which led to increased seal wear. After a number of years this resulted in
intercooler pump seal leakage.
PSEG personnel identified the underlying causal factors leading up to this condition
were inadequate verification of thrust bearing oil groove size prior to bearing installation.
Additionally, PSEG maintenance procedures were inadequate to identify this problem,
because they did not ensure pump shaft axial movement was checked during periodic
pump maintenance. Contributing causes included omitted information in the vendor
manual regarding pump thrust and a past, inappropriate heavy reliance on vendor
representatives to provide this technical guidance during performance diesel
maintenance. Corrective actions included replacing the seized bearing, improving the
verification of critical bearing characteristics, verifying other similar installed EDG
bearings were not affected, and improving applicable maintenance procedures to check
for pump shaft and bearing performance during seal periodic seal replacements. Based
on this review the inspectors concluded the evaluation and corrective actions were
adequate to prevent recurrence.
Notwithstanding, the inspectors concluded the evaluation did not identify past problem
identification performance weaknesses. By design, leakage from either the intercooler
pump oil seal or jacket water seal was directed to a common telltale pipe. The
inspectors determined that notification 20140755 was initiated on April 21, 2003 to
identify an 80 drops per minute (dpm) telltale pipe oil leak during a monthly surveillance
test. On April 25 the intercooler pump was leaking approximately 30 dpm of jacket
water with the EDG in standby (notification 20141433). On May 26 the intercooler pump
seal leaked 80 dpm oil during EDG testing. Subsequently, in June the seal leakage
increased and the EDG was declared inoperable. The leakage was sampled at that
27
Enclosure
time and found to be jacket water. The sample was black in color due to carbon wear
from the pump seal face.
The inspectors concluded that a more in-depth technical assessment of these leaks in
April and May by PSEG engineering personnel could have helped identify the problem
of excessive pump shaft movement. Leaks alternating from oil to jacket water as
described in the notifications may indicate significant shaft movement as the shaft
moves to different positions during run and standby conditions. Additionally, if
personnel had sampled the oil leak they may have identified jacket water with carbon
that was indicative of abnormal pump seal carbon face wear. However, the inspectors
determined the initial assessments of these leaks focused on the ability of the jacket
water and lubrication oil systems to make-up the losses and not on the nature of the
leaks.
The inspectors identified a similar instance of less than adequate initial problem
assessment during the monthly surveillance testing of the C EDG on October 21.
During the test lube oil leakage was observed from a bolted joint that feeds the main
shaft seal. PSEG personnel initiated notification 20163353 and characterized the
problem as a housekeeping leak because the leak-rate was well within the lube oil
make-up system capacity. The inspectors walked down the same joint on the other
EDGs and determined the A and C EDGs had similar leaks. Additionally, the inspectors
observed inconsistencies in the hardware installed between EDGs. The inspectors
further reviewed the maintenance history and determined these joint leaks were
repetitive. The inspectors provided these observations to PSEG personnel who initiated
notifications 20164369, 20164433 and 20164434 to identify undocumented
modifications on the A, B and C EDGs. Additionally, bolt torque checks were performed
and information added to the notification problem descriptions regarding the joint design
and ability to hold pressure. The inspectors concluded this issue was minor, because
the oil leaks did not impact the EDG reliability. However, this is a similar instance of less
than adequate initial problem assessment of EDG leaks.
2.
Cross-References to PI&R Findings Documented Elsewhere
Section 1R12 describes a finding regarding the failure of the A SSWS traveling screen
that was caused by improper cutting of a key without maintenance procedure guidance.
The inspectors identified additional problems regarding traveling chain tensioning and
inspection that were not identified by PSEGs evaluation. Additionally, the finding
involved problem identification aspects because traveling screen binding problems were
not identified when a shear pin failed.
Section 1R16 describes a finding regarding a workaround condition regarding feedwater
heater system isolation. This finding involved ineffective corrective actions.
Section 1R16 also describes a finding regarding a feedwater system setdown setpoint
design problem that was identified through the inspectors questions. This finding
involved a problem identification aspect.
28
Enclosure
4OA3 Event Followup (71153)
1.
(Closed) LER 50-354/03-003, As Found Values for Safety Valve Lift Setpoints Exceed
Technical Specification Allowable Limits
On April 26, 2003 PSEG determined that the as-found lift setpoint for eight of fourteen
main steam safety relief valves (SRV) failed to open within the required Technical
Specification (TS) actuation pressure setpoint tolerance. TS 3.4.2.1 provides an
allowable pressure band of +/- 3 percent for an individual SRV. All eight of the SRVs
opened above the required pressure band (actual range was +3.1 to +7.5 percent).
PSEG determined that the apparent cause for six of the setpoint failures was due to
corrosion bonding/sticking of the pilot disc, and the apparent cause of the other two
failures was due to pilot seat leakage. All fourteen SRVs were replaced with tested and
certified spare pilot assemblies.
The inspectors determined the finding was more than minor, because it affected the
mitigating systems cornerstone objective of ensuring equipment reliability of the SRVs to
perform their intended safety function. The finding was associated with the equipment
performance attribute of the mitigating systems cornerstone. However, the finding was
determined to have very low safety significance (Green) using the SDP Phase 1
screening worksheet for mitigating systems, because there was no loss of system safety
function. This licensee-identified finding involved a violation of TS 3.4.2.1. The
enforcement of licensee identified violations is discussed in Section 4OA7 of this report.
This LER is closed.
2.
(Closed) LER 50-354/03-008, Manual Reactor Scram Following Electro-Hydraulic
Control (EHC) Oil Leak
This LER described a manual reactor scram due to a EHC oil leak on a combined
intermediate control valve (CIV). The LER discussed the plant response to the reactor
scram, including the isolation of the 1st and 2nd stage feedwater heater strings. The
inspectors reviewed the EHC leak in NRC Inspection Report 50-354/2003-07 and the
feedwater heater string isolation in this report, Section 1R16. This LER is closed.
3.
(Closed) LER 50-354/03-007, Reactor Scram Due to Electrical Transient, Low Reactor
Water Level and Loss of Reactor Feed Pumps A and C
a.
Inspection Scope
This LER documents an event that occurred on September 19 in which an electrical
transient in the 500 kv switchyard resulted in two reactor feedwater pumps tripping and
a low reactor water level condition. The reactor automatically scrammed on the low
level condition. The inspectors reviewed the LER and supporting root cause evaluation
to verify that the contributing causes were identified and corrective actions were initiated
to address each causal factor to prevent recurrence. The inspectors initial review of
operator performance and plant response prior to completion of the root cause
29
Enclosure
evaluation is documented in NRC Inspection Report 50-354/2003-005, Section 1R14
dated November 10, 2003.
b.
Findings
Introduction. An inadequate design change and incorrect calibration of an oil control
switch reduced the reliability of the reactor feedwater pumps, such that a second pump
did not remain in operation following the September 19, 2003 electrical transient. The
reactor automatically scrammed on the resulting low reactor level. A Green self-
revealing finding was identified.
Description. On September 19 an electrical transient in the 500 kV switchyard caused
power to be lost from some plant components. The three reactor feed pumps (RFPs)
were affected as follows:
A RFP lost power to both the main and auxiliary oil pumps and tripped.
B RFP retained power to the main and auxiliary oil pumps and continued to
operate.
C RFP lost power to the main oil pump but retained power to the auxiliary oil
pump and should have continued to operate.
The C RFP auxiliary oil pump started on low oil pressure and should have been able to
maintain an acceptable oil pressure; however, it did not and the C RFP tripped, causing
a low reactor water level which caused the reactor scram.
PSEG performed a root cause investigation and identified the likely causal factors that
contributed to the trip of the C RFP. PSEG personnel determined that the reactor feed
pump oil system keep fill lines were undersized and may have been clogged, thereby
allowing a void to form in the standby pump discharge piping. The presence of a void
could have delayed restoration of pressure by the auxiliary oil pump. The keepfill oil line
was installed in 1986 based on recommendations by the pump vendor to install an oil
line that included a 1/16 inch diameter orifice. However PSEG determined the installed
keepfill line was undersized, because the tubing itself was 1/16 inside diameter. This
reduced keepfill flow and was a likely causal factor in the failure of the C RFP auxiliary
oil pump to maintain adequate oil pressure.
PSEG identified a second causal factor for the C RFP turbine was incorrect calibration
of the control oil header pressure switch that started the auxiliary oil pump. The switch
had been calibrated to an incorrect setpoint in March 2003 such that the auxiliary oil
pump started when oil pressure was 10 psig lower then the design setpoint of 86 psig.
PSEG concluded this was likely caused because of an incorrect assumption by the
technician who performed the calibration that the switch operated on increasing
pressure instead of decreasing pressure. The inspectors reviewed notification
20168195 and determined the extent of this problem was adequately addressed and
corrective actions implemented to check other similar calibration tasks.
30
Enclosure
At the end of the inspection period PSEG continued to evaluate RFP performance to
determine whether there were was an additional causal factor related internal oil system
check valve tightness. In the interim PSEG implemented corrective actions to operate
both the main and auxiliary oil pumps associated with each RFP until corrective actions
are finalized.
The inspectors concluded the evaluation was of sufficient detail to identify likely causal
factors and the corrective action to run both oil pumps should ensure RFP reliablity until
corrective actions are finalized. However the inspectors observed that a similar problem
occurred previously in 1999 when the A and B RFP operating main oil pumps tripped
due to an electrical transient. The A and B RFP auxiliary oil pumps both started, but the
A RFP auxiliary pump did not maintain adequate oil pressure to prevent the A RFP from
tripping trip on low oil pressure. PSEGs evaluation (70000775) concluded the A RFP
tripped because an oil accumulator bladder leaked. However, in performing the root
cause evaluation for the September 19 event, PSEG concluded the accumulator was
not designed to maintain oil pressure during pump start.
Analysis. Although PSEG identified the causal factors for this problem, the unreliability
of the C RFP oil system occurred through a self-revealing event. The performance
deficiencies associated with this finding were inadequate design control and inadequate
maintenance. The inspectors determined that the finding was more than minor,
because it affected the design control (modifications) attribute of the Initiating Events
Cornerstone. Unreliable RFP performance resulted in a low water level and reactor
scram during an electrical transient. The inspectors reviewed this finding using the
Phase 1 SDP worksheet for initiating events and determined that a Phase 2 analysis
was needed, because the finding contributed to both the likelihood of a reactor trip and
unavailability of mitigating equipment. Specifically, the failure of the C RFP after the
electrical transient contributed to a reactor scram and it was not available to pump
feedwater to the reactor vessel after the initiating event.
The inspectors completed a SDP Phase 2 evaluation and determined that the finding
was of very low safety significance (Green). The inspectors used the following
assumptions in the Phase 2 evaluation:
An exposure time of greater then 30 days.
The initiating event likelihood was increased by one order of magnitude, because
the amount of increase in the frequency of the initiating event due to the
inspection finding was not known.
The power conversion system (PCS) mitigating capability was reduced by one
order of magnitude to reflect the performance deficiency.
Operator recovery credit was assumed, because the pumps could be manually
restarted and oil pressure was recoverable after a RFP trip.
The performance deficiency impacted the transient initiating events and not the
loss of coolant initiating events, therefore only the transient SDP worksheet was
evaluated.
31
Enclosure
The inspectors determined that two dominant core damage sequences existed for a
transient (reactor trip) event. The first sequence involved a failure of PCS, containment
heat removal (CHR), and containment venting (CV). The second sequence involved a
failure of PCS, high pressure injection (HPI), and depressurization.
Enforcement. This finding was not a violation of NRC requirements. The RFPs have a
meaningful contribution to the risk assessment of plant operations and the Initiating
Events Cornerstone was affected in this case. Nonetheless, the finding occurred on the
RFPs, which are non-safety related components. PSEG entered this issue into its
corrective action program as notifications 20158787 and 20168195. This LER is closed.
(FIN 50-354/03-06-05)
4OA6 Meetings, Including Exit
On January 21, 2004 the inspectors presented their overall findings to members of
PSEG management led by Mr. Jim Hutton. PSEG management stated that none of the
information reviewed by the inspectors was considered proprietary.
4OA7 Licensee-Identified Violations.
The following violations of very low significance (Green) were identified by PSEG and
are violations of NRC requirements which meet the criteria of Section VI of the NRC
Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.
TS 3.4.2.1, "Safety/Relief Valves," requires that 13 of the 14 SRVs open within a
lift setpoint of +/- 3 percent of the specified code safety valve function lift setting.
Contrary to this requirement, PSEG identified that 8 of 14 SRVs experienced
setpoint drift outside of the TS limit. PSEG entered this issue into their corrective
action program as notification 20143634. This finding is of very low safety
significance because the SRVs would have functioned to prevent a reactor
vessel over pressurization.
Plant Technical Specification 6.12.1 requires that areas having radiation dose
rates in excess of 100 millirem per hour be posted, barricaded and access
controlled as a high radiation area. On December 16, 2003, PSEG determined
that the radiation levels in room 3326 (Waste Filter Holding Pump Room) were
600 millirem per hour, but the room was not posted or controlled as a high
radiation area, nor was the area barricaded. This event is documented as
notification 20170646. This finding is of very low safety significance, because it
did not involve a locked high or very high radiation area or personnel over-
exposure.
ATTACHMENT: SUPPLEMENTAL INFORMATION
A-1
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
C. Banner, EP Supervisor
D. Bartlett, System Engineer
M. Bergman, System Engineer
D. Boyle, Hope Creek Operations Superintendent
B. Blomquist, System Engineer
D. Burgin, EP Manager
T. Cellmer, Radiation Protection Manager
M. Conroy, Senior Engineer, Maintenance Rule Coordinator
M. Crisafulli, Hope Creek, Mechanical Superintendent
M. Dammann, Maintenance Manager - Controls & Power Distribution
J. Dower, Hope Creek Training Supervisor
D. Groves, Valve Engineer
A. Faulkner, Hope Creek Training Instructor
J. Frick, Shipping Supervisor
C. Johnson, Valve Engineer
J. Hutton, Hope Creek Plant Manager
B. Nurnberger, Hope Creek Chemistry Superintendent
D. Price, Refueling/Outage Manager
L. Rajkowski, Hope Creek System Engineering Manager
J. Reid, Operations Training Leader
B. Sebastian, Radiation Protection Manager
G. Sosson, Hope Creek Operations Manager
B. Thomas, Sr. Licensing Engineer
P. Tocci, Hope Creek Maintenance Manager
B. Tyers, System Engineer
L. Wagner, Plant Support Manager
R. Yewdall, Licensing
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed
50-354/03-06-01
Improper Reactivation of Limited Senior Reactor Operator
(Section 1R11)
50-354/03-06-02
Ineffective Resolution of Feedwater System Workaround
Condition (Section 1R16)
A-2
Attachment
50-354/03-06-03
Ineffective identification of Feedwater Setdown Setpoint Function
(Section 1R16)
50-354/03-06-04
Failure to Correctly Translate Design Basis for SRV Leakage
Limits into Procedure Requirements (Section 1R23)
50-354/03-06-05
Inadequate Design Control and Maintenance Results in Unreliable
RFPT Operation (Section 4OA3.3)
Closed
50-354/03-003
LER
As Found Values for Safety Valve Lift Setpoints Exceed Technical
Specification Allowable Limits (Section 4OA3.1)
50-354/03-007
LER
Reactor Scram Due to Electrical Transient, Low Reactor Water
Level and Loss of Reactor Feed Pumps A and C (Section
4OA3.3)
50-354/03-008
LER
Manual Reactor Scram Following Electro-Hydraulic Control Oil
Leak (Section 4OA3.2)
Discussed
50-354/03-05-02
Inadequate Procedure Adherence During Maintenance on A
SSWS Traveling Screen (Section 1R12)
LIST OF DOCUMENTS REVIEWED
In addition to the documents identified in the body of this report, the inspectors reviewed the
following documents and records:
Hope Creek Generating Station (HCGS) Updated Final Safety Analysis Report
Technical Specification Action Statement Log (SH.OP-AP.ZZ-108)
HCGS NCO Narrative Logs
HCGS Plant Status Reports
Weekly Reactor Engineering Guidance to Hope Creek Operations
Hope Creek Operations Night Orders and Temporary Standing Orders
Equipment Alignment (71111.04)
Service Water System Operation (HC.OP-SO.EA-0001)
Service Water Traveling Screens System Operation (HC.OP-SO.EP-0001)
Emergency Diesel Generator Operations (HC.OP-SO.KJ-0001)
Safety and Turbine Auxiliaries Cooling Water System Operations (HC.OP-SO.EG-0001)
Control Area Chilled Water System Operation (HC.OP-SO.GJ-0001)
A-3
Attachment
Control Area Ventilation System Operation (HC.OP-SO.GK-0001)
Safety and Turbine Auxiliaries Cooling Water System Operation (HC.OP-SO.EG.0001)
EA B SSW Pump Backwash Valve Replacement Tagging Work List
Hope Creek Generating Station Service Water P&ID (M-10-1), Sheet 1 of 4
Notification 20165973
Licensed Operator Requalification (71111.11)
NC.NA-AP.ZZ-0014(Q) Rev 10 Training, Qualification, and Certification
NC.TQ-TC.ZZ-0306(Z) Rev 1 Limited Senior Reactor Operator (LSRO) Training Program
SH.TQ-TC.ZZ-0303(Z) Rev 14 NRC Licensed Operator Requalification Program
SH.OP-DD.ZZ-0067(z) Rev 1 Personnel Qualification and Training
LSRO Task Lists
Operability Assessment and Equipment Control Program (SH.OP-AP.ZZ-0108)
Reactor Scram (HC.OP-AB.ZZ-0000)
Grid Disturbance (HC.OP-AB.BOP-0004)
Reactor/Pressure Vessel (RPV) Control (HC.OP-EO.ZZ-0101)
Primary Containment Control (HC.OP-EO.ZZ-0102)
Emergency RPV Depressurization (HC.OP-EO.ZZ-0202)
Notification: 20169073
Orders: 70035178, 70034843
Maintenance Effectiveness (71111.12)
System Function Level Maintenance Rule VS Risk Reference (SE.MR.HC.02)
NRC Regulatory Guide 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power
Plants, Revision 2
NUMARC 93-01, Industry Guideline For Monitoring the Effectiveness of Maintenance at Nuclear
Power Plants, Revision 2
Fire Protection (KC & QK) System Health Report, Period 10/01/02 to 12/31/2002
Fire Protection (KC & QK) System Health Report, Period 03/15/03 to 06/15/2003
Fire Protection (KC & QK) System Health Report, Period 06/15/03 to 09/15/2003
FRVS (GU) System Health Report, Period 10/1/02 to 12/20/02
FRVS (GU) System Health Report, Period 03/01/03 to 05/31/03
FRVS (GU) System Health Report, Period 06/01/03 to 08/31/03
Notifications: 20162120, 20069111, 20154871, 20055844, 20160858, 20154430, 20117903,
20103021, 20124148, 20092942, 20100455, 20102413, 20107576, 20107823, 20108331,
20108584, 20110484, 20131200, 20132009, 20132317, 20132339, 20132983,
20134877,20135053, 20138664, 20139763, 20140089, 20143377, 20144213, 20146834,
20153065, 20153221, 20158688, 20166852 , 20074269.
Orders: 60038582, 70033078, 70000121, 80060715
Maintenance Risk Assessment and Emergent Work Control (71111.13)
System Function Level Maintenance Rule VS Risk Reference (SE.MR.HC.02)
HCGS PSA Risk Evaluation Forms for Work Week Nos. 143(10) to 156(12)
On-Line Risk Assessment (SH.OP-AP.ZZ-108)
NRC Regulatory Guide 1.182, Assessing and Managing Risk Before Maintenance Activities at
Nuclear Power Plants
A-4
Attachment
NUMARC 93-01, Industry Guideline For Monitoring the Effectiveness of Maintenance at Nuclear
Power Plants, Section 11- Assessment of Risk Resulting from Performance of Maintenance
Activities, dated February 11, 2000
Operator Performance During Non-Routine Evolutions and Events (71111.14)
TARP Report - 11/15/03 Hope Creek Grid Disturbance due to 500 kV Line [5015] Marsh Fire
Shutdown From Rated Power (HC.OP-IO.ZZ-0004)
Preparation For Plant Startup (HC.OP-IO.ZZ-0002)
Notifications: 20166852
Operability Evaluations (71111.15)
Operability Assessment and Equipment Control Program (SH.OP-AP.ZZ-0108)
NRC Generic Letter No. 91-18, Revision 1, Resolution of Degraded and Nonconforming
Conditions
Notification Process (NC.WM-AP.ZZ-0000)
Service Water Subsystem A Valves - Inservice Test (HC.OP-IS.EA-0101)
Calculation EA-0012, Rev. 3 Service Water Lubrication Header Size and Available Head
Operation and Maintenance Manual for Solenoid Valves (PJ603Q-0042-03)
Update Final Safety Analysis Report Section 9.5.8, Standby Diesel Generator Combustion Air
Intake and Exhaust System
Memorandum FROM W. Capper TO Hope Creek Operations SUBJECT Scramming Control
Rods with Speed Problems, dated September 27, 2003
Letter FROM N. Sadeghi TO C. Brennan SUBJECT Control Rod Withdrawal Speed
Assessment for Hope Creek, dated April 4, 1996 (NFSI 96-163)
CRD Insertion and Withdraw Speed Test, Adjustment, and Stalled Flows (HC.OP-FT.BF-0001)
Reactor Manual Control System Operation (HC.OP-SO.SF-0001)
HC.RE-ST.BF-0001 Form 2, Single Control Rod Scram Checklist: Control Rod 50-19 (9/27/03)
HC.RE-ST.BF-0001 Form 2, Single Control Rod Scram Checklist: Control Rod 34-15 (9/27/03)
HC.RE-ST.BF-0001 Form 2, Single Control Rod Scram Checklist: Control Rod 34-07 (9/27/03)
HC.RE-ST.BF-0001 Form 2, Single Control Rod Scram Checklist: Control Rod 14-43 (9/27/03)
HC.RE-ST.BF-0001 Form 2, Single Control Rod Scram Checklist: Control Rod 22-59 (9/27/03)
HC.RE-ST.BF-0001 Form 2, Single Control Rod Scram Checklist: Control Rod 22-11 (9/27/03)
HC.OP-FT.BF-0001 Attachment 1, CRD Insertion and Withdraw Speed Test, Adjustment, and
Stalled Flows, dated October 7, 2003. (70033715)
P&ID Control Rod Drive Hydraulic (Dwg. 47-1)
UFSAR Section 15.4.1.2, Continuous Rod Withdrawal During Reactor Startup
NRC Inspection Report 50-354/96-03
Operations Department Night Order - Basis for Selection of Control Rods for Speed Time
Testing HC-2003-62, dated October 6, 2003
HC.OP-IS.BE-0103, Core Spray System Valvs - Cold Shutdown Inservice Test, Rev 14
Notifications: 20158056, 20162587, 20166354, 20166355, 20166356, 20155357, 20169632,
20168094, 20167580, 20167754, 20168995, 20168984 and 20171776
Orders: 50065906, 60035544, 60039433, 60039610, 60039491, 70033715, 70034940,
70034874, 70035290
Operator Workarounds (71111.16)
A-5
Attachment
Condition Resolution Operability Determination Notebook
Inoperable Instrument/Alarm/Indicators/Lamps/Device Log
Inoperable Computer Point Log
Hope Creek Operator Workaround List
Hope Creek Operator Concerns List
Technical Issues Fact Sheet, 1 and 2 FWH Isolated Following Reactor Scram, October 8,
2003
Engineering Document H-1-AE-ECS-0128, Digital Feedwater Control System, Rev. 0
Notifications: 20161375, 20161063, 20159307, 20103628, 20164378
Permanent Plant Modifications (71111.17)
UFSAR Section 9.2.7.2, Control Area Chilled Water System
Chiller Unit & Compressor P.M. (HC.MD-PM.GJ-0001)
1989 DCP to Install Oil Recovery System (4-HM-0158)
NRC INFO 94-82, Effect of Cold Condenser Water Temperatures on Chiller Performance
Notifications: 20128071, 20167910, 20169122, 20161055, 20160986, and 20168094
Orders: 60039404, 60037671, 70033848, 70033961, 80064555
Post Maintenance Testing (71111.19)
Maintenance Testing Program Matrix (NC.NA-TS.ZZ-0050)
B Fuel Pool Cooling Pump (BP211) Functional Test Semi-Annual and After Pump Maintenance
(HC.OP-FT.EC-0002)
C SACS Pump-CP210- Inservice Test (HC.OP-IS.EG-0003)
Reactor Core Isolation Cooling Pump Inservice Test (HC.OP-IS.BD-0001)
Notification: 20162297
Refueling and Other Outage Activities (71111.20)
Outage Management Program (NC.NA-AP.ZZ-0055)
Outage Risk Assessment (NC.OM-AP.ZZ-0001)
Preparation for Plant Startup (HC.OP-IO.ZZ-0002)
Startup From Cold Shutdown to Rated Power (HC.OP-IO.ZZ-0003)
Shutdown From Rated Power to Cold Shutdown (HC.OP-IO.ZZ-0004)
Shutdown Cooling (HC.OP-AB.RPV-0009)
Startup Readiness Evaluation for Drywell Debris Condition
P&ID Main Steam (Dwg M-01-1)
Notifications: 20170791, 20170515, 20170738, and 20170485
Surveillance Testing (71111.22)
B & D Core Spray Pump -BP206 and DP206 Inservice Test (HC.OP-IS.BE-0002)
Emergency Diesel Generator BG400 Operability Test - Monthly (HC.OP-ST.KJ-0002)
Temporary Plant Modifications (71111.23)
Log 3 Control Console Log Condition 1, 2, 3 (HC.OP-DL.ZZ-0003)
Target Rock Engineering Test Report Model 756F SRV Leakage Tolerance Test (VTD 325477)
FAB Isometric Main Steam R.V. Discharge From Line A (DWG 1-P-AB-019)
FAB Isometric Main Steam R.V. Discharge From Line B (DWG 1-P-AB-025)
A-6
Attachment
FAB Isometric Main Steam R.V. Discharge From Line C (DWG 1-P-AB-030)
FAB Isometric Main Steam R.V. Discharge From Line D (DWG 1-P-AB-033)
FAB Isometric Main Steam R.V. Discharge From Line C (DWG 1-P-AB-028)
FAB Isometric Main Steam R.V. Discharge From Line B (DWG 1-P-AB-027)
FAB Isometric Main Steam R.V. Discharge From Line C (DWG 1-P-AB-031)
FAB Isometric Main Steam R.V. Discharge From Line D (DWG 1-P-AB-032)
FAB Isometric Main Steam R.V. Discharge From Line A (DWG 1-P-AB-021)
FAB Isometric Main Steam R.V. Discharge From Line B (DWG 1-P-AB-026)
FAB Isometric Main Steam R.V. Discharge From Line C (DWG 1-P-AB-029)
FAB Isometric Main Steam R.V. Discharge From Line D (DWG 1-P-AB-034)
FAB Isometric Main Steam R.V. Discharge From Line B (DWG 1-P-AB-024)
FAB Isometric Main Steam R.V. Discharge From Line A (DWG 1-P-AB-020)
Order: 70034486
Emergency Preparedness (71114)
PSEG Nuclear Emergency Plan
Emergency Plan Implementing Procedures
NC.EP-DC.ZZ-0010, EP Self-assessment Guide
NEP-PER-02-001A, Ability to Perform Self-Assessments, July 18, 2002
NEP-PER-02-002A, ERO Qualifications Self Assessment, July 23, 2002
QA Assessment Report 2002-0210, 10 CFR 50.54(t) EP review, September 30, 2002
QA Assessment Monitoring Feedback 2002-0274, Unannounced Drill, September 23, 2002
QA Assessment Report 2003-0020, Salem Practice Exercise, March 12, 2003
QA Assessment Report 2003-0180, Unannounced Drill, June 25, 2003
QA Assessment Report 2003-0240, Hope Creek Drill
QA Assessment Report 2003-0197, NRC Performance Indicators
QA Emergency Preparedness Integrated Master Assessment Plan
NEP-PER-02-004A, Facilities and Equipment Readiness, 12/2002
NEP-PER-03-001A, Quality of Response to Plant Events or Drill/Exercise Scenarios, 4/2003
NEP-RV-03-001D, Observation of the Corrective Action Program in EP, 3/2003
NEP-RV-03-001B, Salem/HC Technical Document Room Program Capabilities, 3/2002
NEP-PER-03-001C, How effectively workers and their supervisors utilize operating experience
information in Emergency Preparedness, 3/2003
NEP-PER-03-002B, Human Performance Action Plan Status, June/2003
CR No. 80063899-0050, Performance Issues in the TSC and Control Point
CR No. 80063897-0030, Conflicting Information at Joint News Center During Exercise
CR No. 20148989, Interface Between ERO Callout System and ERO Pager System
CR No. 20148989, Untimely Activation of TSC
CR No. 20146629, Accountability Problems
Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems (71122.01)
Notifications: 20151430, 20139438, 20159121, 20170309, 20128081, 20156913, 20105187,
20115491, 20120085, 20127284, 20134459, 20137227, 20139732, 20124966, 20109299,
21032318, 20132387, 20158069, 20158423, 20160969, 20162200, 20169647, 21169766,
20128023, 20128081, 20139438
A-7
Attachment
Radioactive Material Processing and Transportation (71122.02)
Areas Inspected:
Service/Radwaste Building elevation 54, cubicles containing:
- Waste surge tank and pumps
- A, B Floor drain sample tanks and pumps
- Waste sample tanks A & B and pumps
- Waste evaporator packages A & B
- Neutralizer tanks A & B and pumps
- Concentrator tanks A & B and pumps
- Waste collector tanks A & B and pumps
- A, B Cleanup phase separators and
pumps
- Cation and anion vessel and pumps
- Decon solutions concentrated waste tank
and pumps
- Decon solutions concentrator package
- Waste sludge phase separator and pumps
- Spent resin tank and pumps
- Chemical waste tank and pumps
- Floor drain collector tanks A & B and pumps
- Detergent drain tank and pumps
Service/Radwaste Building elevation 102, cubicles containing:
- Fuel pool filter hold pumps
- Floor drain hold pumps
- Waste filter hold pumps
- Dry waste compactor
- Extruder evaporators A & B
- Centrifuge feed tank
- Crystalizer bottoms tank
- Crystalizer recirculation pump room
- Extruder evaporator turntable rooms
- Extruder evaporator drum processing aisle
Service/Radwaste Building elevation 132, cubicles containing:
- Vapor compressor and pumps
- Crystalizer heater and pumps
- Crystalizer condenser cooler and pumps
Quality Assurance Assessment Report 2003-0229
Quality Assessment Monitoring Feedback 2003-0173
Event Followup (71153)
Instrument Calibration Data Report for Order 30021669, dated March 9, 2003
Instrument Calibration Data Report for Order 60039440, dated September 29, 2003
DeLaval Inc Customer Service Letter (CSL) 0002, dated November 27, 1967
DeLaval Instruction Manual Reactor Feed Pump Turbine (PMO12-0099)
Engineering Change Authorization 4HE-0297
Licensee Event Report 05000325/01-03-001
Licensee Event Report 05000354/03-07-000
TARP Report, Hope Creek Reactor Scram and Loss of Power to T-2, T-4 Transformers and
5037 500 KV Line, dated September 19, 2003 (Notification 20158787)
Feedwater and Subsystem (AE) System Health Report, Period 10/1/02 to 12/31/02
Feedwater (AE/FW/CJ) System Health Report, Period 4/1/03 to 5/31/03
NRC Inspection Report 50-354/99-05
Notifications: 20158787, 20168195, 20159974, 20159657, 20140623, 20159534, 20159417,
20159367, 20159395, 20159396, 20045028, 20054898, 20030272, 20079308
Order: 30068745, 70033575, 70000770
A-8
Attachment
LIST OF ACRONYMS
Alert and Notification System
CFR
Code of Federal Regulations
CHR
Containment Heat Removal
Combined Intermediate Control Valve
CV
Containment Venting
Drill and Exercise Performance
DFCS
Digital Feedwater Control System
dpm
Dose Per Minute
Emergency Action Level
Emergency Response Organization
Filtration, Recirculation and Ventilation System
Hope Creek Generating Station
High-Efficiency Particulate Air (filter)
High Pressure Coolant Injection
High Pressure Injection
IMC
Inspection Manual Chapter
Individual Plant Examination For External Events
LERs
Licensee Event Reports
LOSW
Loss of Service water
LSRO
Limited Senior Reactor Operator
Maintenance Rule
Non Cited Violation
NRC
Nuclear Regulatory Commission
Offsite Dose Calculation Manual
Publicly Available Records
Power conversion system
Performance Indicators
Post Maintenance Testing
Public Service Electric Gas
Quality Control
Reactor Core Isolation Cooling
Reactor Feedwater Pump
Reactor Feedwater Pump Turbine
Radiation Monitoring System
Reactor/Pressure Vessel
SACS
Safety Auxiliaries Cooling System
Significance Determination Process
SMD
Solar Magnetic Disturbances
A-9
Attachment
SSU
Safety System Unavailability
SSWS
Station Service Water System
T-Mod
TARP
Transient Assessment Response Plan
TS
Technical Specification