ML030290638
| ML030290638 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 01/28/2003 |
| From: | Grant G Division Reactor Projects III |
| To: | Kanda W FirstEnergy Nuclear Operating Co |
| References | |
| EA-03-007 IR-02-008 | |
| Download: ML030290638 (48) | |
See also: IR 05000440/2002008
Text
January 28, 2003
EA 03-007
Mr. William Kanda
Vice President - Nuclear
FirstEnergy Nuclear Operating Company
Perry Nuclear Power Plant
P. O. Box 97, A210
Perry, OH 44081
SUBJECT:
PERRY NUCLEAR POWER PLANT
NRC INTEGRATED INSPECTION REPORT 50-440/02-08
Dear Mr. Kanda:
On December 28, 2002, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Perry Nuclear Power Plant. The enclosed report documents the inspection
findings which were discussed on January 9, 2003, with Mr. T. Rausch 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 discusses a finding that appears to have a low to moderate safety significance. As
described in Section 4OA3.3 of this report, this finding relates to failure of your high pressure
core spray system to start during routine surveillance testing on October 23, 2002. This finding
was assessed using the NRC Phase 3 Significance Determination Process and was
preliminarily determined to be White, i.e., a finding with some increased importance to safety,
which may require additional NRC inspection.
This finding is also an apparent violation of NRC requirements and is being considered for
escalated enforcement action in accordance with the "General Statement of Policy and
Procedure for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600. The current
Enforcement Policy is included on the NRCs website at http://www.nrc.gov.
The apparent violation involves the failure to follow procedure GEI-0135, ABB Power Circuit
Breakers 5 KV Types 5HK250 and 5HK350 Maintenance, for breaker installation and
inspection. Specifically, the inspection procedure required confirmation that open contacts are
in the flat, horizontal position. While the procedure allows for deviation from the flat horizontal
alignment, clear make/break of the contacts must be observed. The physical configuration of
the cell switch prevents observation of contact make/break; therefore, the open contacts must
be in the flat, horizontal position to comply with the procedure. In the as found condition, the
cell switch was significantly out of the flat horizontal condition.
W. Kanda
-2-
We believe that sufficient information was considered to make a preliminary significance
determination. However, before we make a final decision on this matter, we are providing you
an opportunity to present to the NRC your perspectives on the facts and assumptions used by
the NRC to arrive at the finding and its significance at a Regulatory Conference or by a written
submittal. If you choose to request a Regulatory Conference, it should be held within 30 days of
the receipt of this letter and we encourage you to submit supporting documentation at least one
week prior to the conference in an effort to make the conference more efficient and effective. If
a Regulatory Conference is held, it will be open for public observation. If you decide to submit
only a written response, such submittal should be sent to the NRC within 30 days of the receipt
of this letter.
Please contact Mark A. Ring at 630-829-9703 within 10 business days of your receipt of this
letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will
continue with our significance determination and enforcement decision and you will be advised
by separate correspondence of the results of our deliberations on this matter.
Since the NRC has not made a final determination in this matter, no Notice of Violation is being
issued for this inspection finding at this time. In addition, please be advised that the number
and characterization of apparent violations described in the enclosed inspection report may
change as a result of further NRC review.
During the inspection period, the inspectors also identified one finding of very low safety
significance (Green). The finding was determined to be a violation of NRC requirements.
However, because of its very low safety significance and because it has been entered into your
corrective action program, the NRC is treating this finding as a Non-Cited Violation in
accordance with Section VI.A.1 of the NRCs Enforcement Policy.
If you contest the subject or severity of a Non-Cited Violation, you should provide a response
within 30 days of the date of this inspection report, with the basis for your denial, to the U.S.
Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC
20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission -
Region III, 801 Warrenville Road, Lisle, IL 60532-4351; the Director, Office of Enforcement, U.S.
Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector
Office at the Perry Nuclear Power Plant.
Since the terrorist attacks on September 11, 2001, the NRC has issued two Orders
(dated February 25, 2002, and January 7, 2003) and several threat advisories to licensees
of commercial nuclear power plants to strengthen licensee capabilities, improve security force
readiness, and enhance access authorization. The NRC also issued Temporary
Instruction 2515/148 on August 28, 2002, that provided guidance to inspectors to audit and
inspect licensee implementation of the interim compensatory measures (ICMs) required by the
February 25th Order. Phase 1 of TI 2515/148 was completed at all commercial nuclear power
plants during calendar year (CY) 02, and the remaining inspections are scheduled for
completion in CY 03. Additionally, table-top security drills were conducted at several licensees
to evaluate the impact of expanded adversary characteristics and the ICMs on licensee
protection and mitigative strategies. Information gained and discrepancies identified during the
W. Kanda
-3-
audits and drills were reviewed and dispositioned by the Office of Nuclear Security and Incident
Response. For CY 03, the NRC will continue to monitor overall safeguards and security
controls and conduct inspections, and will resume force-on-force exercises at selected power
plants. Should threat conditions change, the NRC may issue additional Orders, advisories, and
temporary instructions to ensure adequate safety is being maintained at all commercial nuclear
power plants.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) component of NRC's 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/
Geoffrey E. Grant, Director
Division of Reactor Projects
Docket No. 50-440
License No. NPF-58
Enclosure:
Inspection Report 50-440/02-08
cc w/encl:
B. Saunders, President - FENOC
K. Ostrowski, Director, Nuclear
Maintenance Department
V. Higaki, Manager, Regulatory Affairs
J. Messina, Director, Nuclear
Services Department
T. Lentz, Director, Nuclear
Engineering Department
T. Rausch, Plant Manager,
Nuclear Power Plant Department
Public Utilities Commission of Ohio
Ohio State Liaison Officer
R. Owen, Ohio Department of Health
DOCUMENT NAME: G:\\PERR\\Perry 02-08.wpd
To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy
OFFICE
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DATE
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1/28/03
1/28/03
1/28/03
OFFICIAL RECORD COPY
W. Kanda
-4-
ADAMS Distribution:
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No:
50-440
License No:
Report No:
50-440/02-08
Licensee:
FirstEnergy Nuclear Operating Company (FENOC)
Facility:
Perry Nuclear Power Plant, Unit 1
Location:
P.O. Box 97 A200
Perry, OH 44081
Dates:
October 1, 2002, through December 28, 2002
Inspectors:
Ray Powell, Senior Resident Inspector
John Ellegood, Resident Inspector
John House, Senior Radiation Specialist
Patricia Lougheed, Regional Inspector
Gerard ODwyer, Regional Inspector
Charles Phillips, Senior Operations Engineer
Darrell Schrum, Reactor Inspector
Phillip Young, Examiner
Paul Pelke, Reactor Engineer
Approved by:
Mark A. Ring, Chief
Branch 1
Division of Reactor Projects
2
SUMMARY OF FINDINGS
IR 05000440-02-08; First Energy Nuclear Operating Company; on 10/01-12/28/2002; Perry
Nuclear Power Plant. Post-Maintenance Testing, Event Follow-up.
This report covers a 3-month period of baseline resident inspections; a baseline heatsink
inspection; a baseline radiation protection inspection; an inspection of the Licensed Operator
Requalification Program; and a baseline maintenance rule implementation inspection. The
inspections were conducted by resident and regional specialist inspectors. The inspections
identified one preliminarily White finding which involved an Apparent Violation (AV) and one
Green finding which involved a Non-Cited Violation (NCV). The significance of most findings is
indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter 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.
Inspection Findings
Cornerstone: Mitigating Systems
To Be Determined. An apparent self-revealed violation of Technical Specification (TS) 5.4 occurred when the High Pressure Core Spray (HPCS) pump failed to start
during a surveillance test of the HPCS room cooler. Troubleshooting by the licensee
revealed that contacts in the breaker enclosure that provide a close permissive signal
were misaligned and prevented starting of the HPCS pump. Since the last breaker
replacement, the licensee had performed one post-maintenance test and two
inspections of the circuit breaker that would have detected the misalignment of contacts
had the procedure been properly followed. The finding is identified as Apparent
Violation (AV) 50-440/02-08-02. The NRC assessed this finding through phase 3 of the
SDP and made a preliminary determination that it is an issue with some increased
importance to safety. (Section 4OA3.3)
Cornerstone: Barrier Integrity
Green. The inspectors identified a violation of TS Surveillance Requirement (SR) 3.6.1.9.1 in that the licensee failed to perform TS required surveillance testing and
appropriate post-maintenance testing (PMT) following packing adjustment of a main
steam shutoff valve. Surveillance Requirement R 3.6.1.9.1 specified that the licensee
verify isolation times of main steam shutoff valves at a frequency in accordance with the
Inservice Testing Program. The Inservice Testing Program specifically stated that
following adjustment of stem packing, stroke time testing will be performed. Contrary to
this requirement, no stroke time testing was performed on the valve. The inspectors
also noted that the condition was further aggravated by the licensees use of an
operability determination to declare the valve operable once the missed PMT was
initially identified. The licensee failed to recognize the TS compliance aspect until
prompted, repeatedly, by the inspectors.
3
The inspectors determined that the finding was more than minor because the failure to
perform PMT on a safety related component could reasonably be viewed as a precursor
to a significant event. The finding was of very low risk significance because, although
the barrier integrity cornerstone was affected in that containment systems capability was
not demonstrated through TS required surveillance testing, subsequent testing
demonstrated that the system would have performed its intended safety function.
(Section 1R19)
B.
Licensee-Identified Violations
A violation of very low significance which was identified by the licensee has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensees corrective action program. This violation is listed in
Section 4OA7 of this report.
4
Report Details
Summary of Plant Status
The inspection period began with Unit 1 in mode 4 following a September 22, 2002, scram
which occurred during performance of routine turbine overspeed testing. Following completion
of forced outage maintenance activities, the unit reached criticality on October 3 and
synchronized to the grid on October 5. The unit reached approximately 94 percent power on
October 7, with maximum core flow. Power was reduced to approximately 60 percent on
October 8 to perform a rod line adjustment. Following the rod line adjustment, 100 percent
power was achieved on October 9. The unit remained at or near 100 percent power until
October 12 when power was reduced to approximately 75 percent to perform an additional rod
line adjustment. The unit was returned to 100 percent power later that same day.
The unit slowly decreased power from October 15 through October 27 due to maximum core
flow limitations. On October 27, power was reduced to approximately 68 percent for a rod line
adjustment and testing of a main steam stop valve. The unit remained at or near 100 percent
power until December 1, when power was reduced to approximately 70 percent for a planned
rod line adjustment. With the exception of planned down powers to 90 or 95 percent for weekly
rod exercises, the unit remained at 100 percent power for the remainder of the inspection
period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01
Adverse Weather (71111.01)
a.
Inspection Scope
During the weeks of October 28 and November 4, 2002, the inspectors reviewed the
licensees cold weather readiness to verify that cold weather protection features such as
heat tracing and space heaters were monitored and functional; that plant features and
procedures for cold weather operations were appropriate; and that operator actions
specified in the licensees cold weather preparation procedures verified the readiness of
essential systems. Specifically, the inspectors:
conducted walkdowns of various plant structures and systems to check for
maintenance or other apparent deficiencies that could affect system operations
during cold weather conditions;
reviewed heat trace system calibration data;
reviewed winter preparation repetitive task status;
reviewed heat trace setpoints and area thermostat settings;
reviewed ice melt procedures; and
discussed operational experience with licensee operations and training staffs.
5
b.
Findings
No findings of significance were identified.
1R04
Equipment Alignment (71111.04)
a.
Inspection Scope
The inspectors used licensee valve lineup instructions (VLIs) and system drawings
during the walkdowns. The walkdowns included selected switch and valve position
checks and verification of electrical power to critical components. Finally, the inspectors
evaluated other elements, such as material condition, housekeeping, and component
labeling. The documents used for the walkdowns are listed in the attached List of
Documents Reviewed. The systems reviewed were:
Control Room Heating, Ventilation, and Air Conditioning Train B while Train A was
inoperable for planned maintenance during the week of October 21, 2002;
Division 1 Diesel Generator while the Division 2 Diesel Generator was inoperable
due to planned maintenance during the week of November 11, 2002;
Reactor Core Isolation Cooling (RCIC) system while the High Pressure Core Spray
(HPCS) system was inoperable due to planned Division 3 Diesel Generator
maintenance during the week of November 18, 2002;
HPCS system while the RCIC system was inoperable due to planned maintenance
during the week of December 2, 2002; and
Emergency Closed Cooling Water system during a planned Division 2 Outage
conducted the week of December 9, 2002.
b.
Findings
No findings of significance were identified.
1R05
Fire Protection (71111.05Q)
.1
Walk-down of Selected Fire Zones
a.
Inspection Scope
The inspectors walked down the following areas to assess the overall readiness of fire
protection equipment and barriers:
Fire Zone IB-2, Intermediate Building Elevation 599'-0";
Fire Zone IB-3, Intermediate Building Elevation 620'-6";
Fire Zone IB-4, Intermediate Building Elevation 654'-6" and 665'-0";
Fire Zone IB-5, Intermediate Building Elevation 682'-0";
Fire Area 1DG-1B, Div 3 Diesel Generator;
Fire Area 1CC-3B, Div 3 Switchgear;
Fire Area 1CC-3C, Remote Shutdown Panel;
Fire Area 1AB-1g, Common Corridor for Floor 1 of the Auxiliary Building;
6
Fire Area 1AB-3b, Auxiliary Building, 620'-6" (West);
Fire Area CC-2, Control Complex Elevation 599'-0"; and
Fire Area CC-4, Control Complex Elevation 638'-6".
Emphasis was placed on the control of transient combustibles and ignition sources, the
material condition of fire protection equipment, and the material condition and
operational status of fire barriers used to prevent fire damage or propagation.
The inspectors looked at fire hoses, sprinklers, and portable fire extinguishers to verify
that they were installed at their designated locations, were in satisfactory physical
condition, and were unobstructed. The inspectors also evaluated the physical location
and condition of fire detection devices. Additionally, passive features such as fire doors,
fire dampers, and mechanical and electrical penetration seals were inspected to verify
that they were in good physical condition. The documents listed at the end of the report
were used by the inspectors during the assessment of this area.
b.
Findings
No findings of significance were identified.
.2
Observation of Unannounced Fire Drill
a.
Inspection Scope
The inspectors observed an unannounced drill concerning a fire in an electrical cubicle
on November 26, 2002. The drill was observed to evaluate the readiness of licensee
personnel to fight fires. The inspectors considered licensee performance in donning
protective clothing/turnout gear and self-contained breathing apparatus, deploying
firefighting equipment and fire hoses to the scene of the fire, entering the fire area in a
deliberate and controlled manner, maintaining clear and concise communications,
checking for fire victims and propagation of fire and smoke into other plant areas, smoke
removal operations, and the use of pre-planned fire fighting strategies in evaluating the
effectiveness of the fire fighting brigade. In addition, the inspectors attended the post-
drill debrief to evaluate the licensee's ability to self-critique fire fighting performance and
make recommendations for future improvement.
b.
Findings
No findings of significance were identified.
1R07
Heat Sink Performance (71111.07)
.1
Biennial Review of Heat Sink Performance
a.
Inspection Scope
The inspector reviewed documents associated with testing, inspection, cleaning and
performance trending of heat exchangers primarily focusing on the Division 1 (Loop A)
7
Emergency Closed Cooling Water (P-42) System Heat Exchanger, and Division 2
(Loop B) Residual Heat Removal Heat Exchanger. These two heat exchangers were
chosen based upon their importance in supporting required safety functions as well as
relatively high risk achievement worth in the plant specific risk assessment. These heat
exchangers were also selected to evaluate the licensee's thermal performance testing
methods. During the inspection, the inspector reviewed completed surveillance tests
and associated calculations, and performed independent calculations to verify that these
activities adequately ensured proper heat transfer. The inspector reviewed the
documentation to confirm that the test or inspection methodology was consistent with
accepted industry and scientific practices, based on review of heat transfer texts and
electrical power research institute standards (EPRI NP-7552, Heat Exchanger
Performance Monitoring Guidelines, December 1991 and EPRI TR-107397, Service
Water Heat Exchanger Testing Guidelines, March 1998) and Marks Engineering
Handbook.
The inspector reviewed condition reports concerning heat exchanger and ultimate heat
sink performance issues to verify that the licensee had an appropriate threshold for
identifying issues and entering them in the corrective action program. The inspector also
evaluated the effectiveness of the corrective actions for identified issues, including the
engineering justification for operability, if applicable.
The documents that were reviewed are included at the end of the report. Also attached
is the information request sent to the licensee in preparation for this Heat Sink
Inspection.
b.
Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11)
.1
Facility Operating History
a.
Inspection Scope
The inspectors reviewed the plants operating history from December 2000 through
October 2002, to assess whether the Licensed Operator Requalification Training
(LORT) program had addressed operator performance deficiencies noted at the plant.
b.
Findings
No findings of significance were identified.
8
.2
Licensee Requalification Examinations
a.
Inspection Scope
The inspectors performed a biennial inspection of the licensees LORT program. The
inspectors reviewed the annual requalification operating and written examination
material to evaluate general quality, construction, and difficulty level. The operating
examination material consisted of three dynamic simulator scenarios and fourteen job
performance measures (JPMs). The biennial written examination consisted of
approximately 40 open reference, multiple choice questions. The written examination
was organized into two parts, Part A and Part B. Part A used the static simulator as
an open reference instrument. Part B was an open reference examination on
administrative controls and procedural limits. The inspectors reviewed the methodology
for developing the examinations, including the LORT program 2 year sample plan,
probabilistic risk assessment insights, previously identified operator performance
deficiencies, and plant modifications. The inspectors reviewed the licensees program
and assessed the level of examination material duplication during the current year
annual examinations as compared to the previous years annual examinations. The
inspectors also interviewed members of the licensees management, operations, and
training staff and discussed various aspects of the examination development.
b.
Findings
No findings of significance were identified.
.3
Licensee Administration of Requalification Examinations
a.
Inspection Scope
The inspectors observed the administration of the requalification operating test to assess
the licensees effectiveness in conducting the test and to assess the facility evaluators
ability to determine adequate performance using objective, measurable performance
standards. The inspectors evaluated the performance of one staff crew in parallel with
the facility evaluators during three dynamic simulator scenarios. In addition, the
inspectors observed licensee evaluators administer eleven JPMs to four licensed
operators. The inspectors observed the training staff personnel administer the operating
test, including pre-examination briefings, observations of operator performance, and
individual and crew evaluations after dynamic scenarios. The inspectors evaluated the
ability of the simulator to support the examinations. A specific evaluation of simulator
performance was conducted and documented under Section 1R11.7, Conformance
With Simulator Requirements Specified in 10 CFR 55.46, of this report. The inspectors
also reviewed the licensees overall examination security program.
b.
Findings
No findings of significance were identified.
.4
Licensee Training Feedback System
9
a.
Inspection Scope
The inspectors assessed the methods and effectiveness of the licensees processes
for revising and maintaining its LORT program up to date, including the use of feedback
from plant events and industry experience information. The inspectors interviewed
licensee personnel (operators, instructors, training management, and operations
management) and reviewed the applicable licensees procedures. In addition, the
inspectors reviewed the licensees quality assurance oversight activities, including
licensees training department self-assessment reports, to evaluate the licensees ability
to assess the effectiveness of its LORT program and to implement appropriate corrective
actions.
b.
Findings
No findings of significance were identified.
.5
Licensee Remedial Training Program
a.
Inspection Scope
The inspectors assessed the adequacy and effectiveness of the remedial training
conducted since the previous annual requalification examinations and the training
planned for the current examination cycle to ensure that they addressed weaknesses in
licensed operator or crew performance identified during training and plant operations.
The inspectors reviewed remedial training procedures and individual remedial training
plans, and interviewed licensee personnel (operators, instructors, and training
management). In addition, the inspectors reviewed the licensees previous Nuclear
Regulatory Commission (NRC) annual examination cycle remediation packages for
unsatisfactory operator performance on the operating test to ensure that remediation
and subsequent re-evaluations were completed prior to returning individuals to licensed
duties.
b.
Findings
No findings of significance were identified.
.6
Conformance With Operator License Conditions
a.
Inspection Scope
The inspectors evaluated the facility and individual operator licensees' conformance with
the requirements of 10 CFR Part 55. The inspectors reviewed the facility licensees
program for maintaining active operator licenses and to assess compliance with
10 CFR 55.53 (e) and (f). The inspectors reviewed the procedural guidance and the
process for tracking on-shift hours for licensed operators and which control room
positions were granted credit for maintaining active operator licenses. The inspectors
also reviewed nine licensed operators medical records maintained by the facilitys
medical contractor and assessed compliance with the medical standards delineated in
10
ANSI/ANS-3.4, American National Standard Medical Certification and Monitoring of
Personnel Requiring Operator Licenses for Nuclear Power Plants, and with
10 CFR 55.21 and 10 CFR 55.25. In addition, the inspectors reviewed the facility
licensees LORT program to assess compliance with the requalification program
requirements as described by 10 CFR 55.59 (c).
b.
Findings
No findings of significance were identified.
.7
Conformance With Simulator Requirements Specified in 10 CFR 55.46
a.
Inspection Scope
The inspectors assessed the adequacy of the licensees simulation facility (simulator) for
use in operator licensing examinations and for satisfying experience requirements as
prescribed in 10 CFR 55.46, Simulation Facilities. The inspectors also reviewed a
sample of simulator performance test records (i.e., transient tests and malfunction tests),
simulator work order records, and the process for ensuring continued assurance of
simulator fidelity in accordance with 10 CFR 55.46. The inspectors reviewed and
evaluated the discrepancy process to ensure that simulator fidelity was maintained. This
was accomplished by a review of discrepancies noted during the inspection to ensure
that they were entered into the licensees corrective action system and by an evaluation
to verify that the licensee adequately captured simulator problems and that corrective
actions were performed and completed in a timely fashion commensurate with the safety
significance of the item (prioritization scheme). Open simulator discrepancies were
reviewed for importance relative to the impact on 10 CFR 55.45 and 55.59 operator
actions as well as on nuclear and thermal hydraulic operating characteristics.
Furthermore, the inspectors conducted interviews with members of the licensees
simulator configuration control group and completed the IP 71111.11, Appendix C,
checklist to evaluate whether or not the licensees plant-referenced simulator was
operating adequately as required by 10 CFR 55.46 (c) and (d).
b.
Findings
No findings of significance were identified.
.8
Written Examination and Operating Test Results
a.
Inspection Scope
The inspectors reviewed the overall Licensed Operator Annual Requalification
Examination pass/fail results of the biennial written exam, individual job performance
measure and simulator operating tests (required to be given per 10 CFR 55.59(a)(2))
administered by the licensee during calender year 2002). The inspectors also reviewed
applicability of the operating test results to the NRC Inspection Manual Chapter 0609,
Appendix IProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix 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).
11
b.
Findings
No findings of significance were identified.
.9
Requalification Activities Review by Resident Staff
a.
Inspection Scope
On November 5, 2002, the resident inspectors observed licensed operator performance
in the plant simulator. The evaluated scenarios included an anticipated transient without
scram, a fire, and turbine building flooding.
The inspectors evaluated crew performance in the areas of:
clarity and formality of communication;
ability to take timely action in the safe direction;
prioritizing, interpreting, and verifying of alarms;
correct use and implementation of procedures, including alarm response procedures;
timely control board operation and manipulation, including high-risk operator actions;
and
group dynamics.
The inspectors also observed the licensees evaluation of crew performance to verify
that the training staff had observed important performance deficiencies and specified
appropriate remedial actions.
b.
Findings
No findings of significance were identified.
1R12
Maintenance Rule Implementation (71111.12)
.1
Periodic Evaluation
a.
Inspection Scope
The objective of the inspection was to:
Verify that the periodic evaluation was completed within the time restraints defined in
10 CFR 50.65, the Maintenance Rule (once per refueling cycle, not to exceed
2 years), ensuring that the licensee reviewed its goals, monitoring, preventive
maintenance activities, industry operating experience, and made appropriate
adjustments as a result of that review;
Verify that the licensee balanced reliability and unavailability during the previous
refueling cycle, including a review of safety significant structures, systems, and
components (SSCs);
Verify that (a)(1) goals were met, corrective actions were appropriate to correct the
defective condition including the use of industry operating experience, and (a)(1)
12
activities and related goals were adjusted as needed; and
Verify that the licensee has established (a)(2) performance criteria, examined any
SSCs that failed to meet their performance criteria, or reviewed any SSCs that have
suffered repeated maintenance preventable functional failures including a verification
that failed SSCs were considered for (a)(1).
The inspectors examined the last two periodic evaluation reports for the time frames
October 1997 through May 1999, and May 1999 through March 2001. To evaluate the
effectiveness of (a)(1) and (a)(2) activities, the inspectors examined (a)(1) action plans,
justifications for returning SSCs from (a)(1) to (a)(2), and a number of Condition Reports
(CRs) (contained in the list of documents at the end of this report). In addition, the CRs
were reviewed to verify that the threshold for identification of problems were at an
appropriate level and the associated corrective actions were appropriate. The
inspectors focused the inspection on the following systems:
DG, Diesel Generator;
HPCS, High Pressure Core Spray;
RHR, Residual Heat Removal System; and
RCIC, Reactor Core Isolation Cooling
In addition, the inspectors reviewed two self-assessments that addressed maintenance
rule implementation at Perry.
b.
Findings
No findings of significance were identified.
.2
Quarterly Review by Resident Staff
a.
Inspection Scope
The inspectors reviewed the licensee's implementation of the Maintenance Rule
requirements to verify that component and equipment failures were identified and
scoped within the Maintenance Rule and that select structures, systems, and
components (SSCs) were properly categorized and classified as (a)(1) or (a)(2) in
accordance with 10 CFR 50.65. The inspectors reviewed station logs, maintenance
work orders, selected surveillance test procedures, and a sample of condition reports
(CRs) to verify that the licensee was identifying issues related to the Maintenance Rule
at an appropriate threshold and that corrective actions were appropriate. Additionally,
the inspectors reviewed the licensees performance criteria to verify that the criteria
adequately monitored equipment performance and to verify that licensee changes to
performance criteria were reflected in the licensees probabilistic risk assessment.
During this inspection period, the inspectors reviewed the Emergency Service Water
system. The problem identification and resolution CRs reviewed are listed in the
attached List of Documents Reviewed.
13
b.
Findings
No findings of significance were identified.
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13)
a.
Inspection Scope
The inspectors reviewed the licensees evaluation of plant risk, scheduling, configuration
control, and performance of maintenance associated with planned and emergent work
activities, to verify that scheduled and emergent work activities were adequately
managed. In particular, the inspectors reviewed the licensees program for conducting
maintenance risk assessments to verify that the licensees planning, risk management
tools, and the assessment and management of on-line risk were adequate. The
inspectors also reviewed licensee actions to address increased on-line risk when
equipment was out of service for maintenance, such as establishing compensatory
actions, minimizing the duration of the activity, obtaining appropriate management
approval, and informing appropriate plant staff, to verify that the actions were
accomplished when on-line risk was increased due to maintenance on risk-significant
SSCs. The following specific assessments were reviewed:
The maintenance risk assessment for Division 2 Diesel Generator allowed outage
time maintenance period during the week of November 10, 2002;
The maintenance risk assessment for work planned for the week beginning
November 18, 2002. The work week included switchyard work, Division 3 Diesel
Generator maintenance, diesel driven fire pump maintenance, and instrumentation
and control surveillances;
The maintenance risk assessment for work planned for the week beginning
December 2, 2002. The work week included a planned RCIC unavailability, Control
Rod Drive Pump A repair work, Emergency Closed Cooling motor operated valve
testing, and Residual Heat Removal (RHR) Heat Exchanger B performance testing;
and
The maintenance risk assessment for the planned Division 2 Outage conducted the
week beginning December 9, 2002.
b.
Findings
No findings of significance were identified.
1R14
Personnel Performance During Nonroutine Plant Evolutions (71111.14)
14
a.
Inspection Scope
The inspectors observed and reviewed activities associated with the October 3, 2002,
unit startup and subsequent grid synchronization on October 5. The inspectors
observed crew communications, preshift briefings, and procedure usage.
b.
Findings
No findings of significance were identified.
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors selected CRs related to potential operability issues for risk significant
components and systems. These CRs were evaluated to determine whether the
operability of the components and systems was justified. The inspectors compared the
operability and design criteria in the appropriate sections of the TSs and Updated Safety
Analysis Report (USAR) to the licensees evaluations to verify that the components or
systems were operable. Where compensatory measures were required to maintain
operability, the inspectors verified that the measures were in place, would work as
intended, and were properly controlled. Additionally, the inspectors verified, where
appropriate, compliance with bounding limitations associated with the evaluations. The
inspectors reviewed Operability Determinations (ODs) associated with:
Containment equipment drain sump cooler potentially undersized, completed
October 15, 2002;
Main steam shutoff valve packing adjustment, completed October 17, 2002;
Scram discharge volume vent and drain valve actuator environmental qualification,
completed October 31, 2002;
Reactor water cleanup pressure and flow transients, completed October 29, 2002
and;
An OD associated with an identified unreviewed manufacturing change to marathon
control rods completed December 6, 2002.
b.
Findings
No findings of significance were identified.
1R16
Operator Workarounds (OWAs) (71111.16)
a.
Inspection Scope
The inspectors accompanied a plant operator, Nuclear Island Radiologically Restricted
Area, during the performance of a normal rounds tour on November 6. The inspectors
observed all log readings and equipment manipulations made by the operator. Any
actions which indicated a potential problem that could increase initiating event
frequencies, impact multiple mitigating systems, or affect the ability to respond to plant
15
transients and accidents were considered as possible OWAs. Additionally, the
inspectors discussed the effect of active OWAs with the operator.
The inspectors evaluated the collective significance of outstanding OWAs to determine if
the cumulative effects of OWAs to evaluate if the combined effects hindered operators
abilities to respond to plant transients and accidents. The inspectors reviewed the OWA
log, individual OWAs and interviewed operators.
b.
Findings
No findings of significance were identified.
1R19
Post-Maintenance Testing (PMT) (71111.19)
a.
Inspection Scope
The inspectors evaluated the following PMT activities for risk significant systems to
assess the following (as applicable): the effect of testing on the plant had been
adequately addressed; testing was adequate for the maintenance performed;
acceptance criteria were clear and demonstrated operational readiness; test
instrumentation was appropriate; tests were performed as written; and equipment was
returned to its operational status following testing. The inspectors evaluated the
activities against TS, the USAR, 10 CFR Part 50 requirements, licensee procedures, and
various NRC generic communications. In addition, the inspectors reviewed CRs
associated with post-maintenance testing to determine if the licensee was identifying
problems and entering them in the corrective action program. The specific procedures
and CRs reviewed are listed in the attached List of Documents Reviewed. The following
post-maintenance activities were reviewed:
Scram discharge volume vent and drain valve leak testing conducted following
coupler replacement on September 30, 2002;
Main steam shutoff valve testing following a packing adjustment on October 5, 2002;
HPCS breaker testing following repair of a breaker cell switch performed on
October 23, 2002;
Standby liquid control testing following preventive maintenance of Limitorque valve
operator on November 7, 2002;
Master trip unit for RHR C Suction Pressure - Low Trip testing following replacement
of Capacitor C25 performed on December 10, 2002; and
RHR testing on December 12, 2002 following preventive maintenance on motor
operated valves.
b.
Findings
16
The inspectors identified a violation of TS Surveillance Requirement (SR) 3.6.1.9.1 in
that the licensee failed to perform TS required surveillance testing, the appropriate post-
maintenance testing, following packing adjustment of a main steam shutoff valve.
On October 5, 2002, the licensee tightened the packing on valve 1N11F0020B, a main
steam shutoff valve. Main steam shutoff valves provide a redundant method to isolate
flow in steam lines to reduce off-site dose in certain post-accident scenarios. The work,
performed on a safety related motor operated valve, was performed using minor work
order number 02-10886. The use of the minor work order was contrary to the
requirements of licensee procedure NOP-WM-9001, Minor Work Order, which did not
allow packing adjustments on safety related motor operated valves. Because a minor
work order was used, Senior Reactor Operator (SRO) review of the work package was
not conducted. After the packing adjustment, no post-maintenance testing was
performed. On October 9, 2002, a licensee reviewer identified the failure to perform post
maintenance testing and on October 16 entered the deficiency in the corrective action
program as CR 02-03829. The shift manager reviewed the CR and requested an OD to
assist in evaluation of the valves status.
The licensees engineering staff completed the OD on October 17 with the
recommendation that the valve be considered operable based on engineering
calculations which concluded that the packing adjustment did not affect the ability of the
valve to close within stroke time limitations. The inspectors noted, however, that the OD
clearly stated that per the requirements of Inservice Testing Program and TS 5.5.6, the
valve would have to be declared inoperable since the PMT was not performed. While
the inspectors realized that the engineering staff was asked for an engineering
evaluation not a compliance assessment, the inspectors were concerned that multiple
members of the engineering staff failed to recognize the TS compliance aspect, and,
most significantly, that a shift manager (a SRO) accepted the OD and declared the valve
Review of the sequence of events by the resident inspectors identified numerous errors,
procedural violations and missed opportunities on the part of the licensee. In aggregate,
these errors raised concerns over the licensees integration of various site perspectives
into a cohesive decision on operability. The errors started with the use of a minor
maintenance package on a safety related motor operated valve. While this error was
discovered during package closeout on October 9, the originator delayed writing the CR
until October 15 with presentation to the shift manager on October 16. As a result,
problem identification and resolution were delayed by a week. When Operations initially
reviewed the CR, the shift manager did not recognize that a TS had been violated and
requested engineering support for an OD. Engineering developed a technical argument
to show that the valve could perform its intended function, however they did not
recognize that an OD could not be used to justify non-performance of a TS required
surveillance. Finally, even though the engineer documented in the OD that TS were not
met, the shift manager accepted the technical basis and declared the system operable.
The inspectors concluded that the licensee was not in compliance with TS requirements.
17
On October 18, the resident inspector discussed the OD with the shift manager, but the
shift manager maintained his position that the OD sufficed as a basis for operability. On
October 21, the inspectors brought this condition to the attention of the Operations
Manager. Subsequently, the licensee declared the valve inoperable and scheduled PMT
for the valve. The PMT was subsequently performed successfully.
Surveillance Requirement 3.6.1.9.1 specified that the licensee verify isolation times of
main steam shutoff valves at a frequency in accordance with the Inservice Testing
Program. The Inservice Testing Program specifically states that following adjustment of
stem packing, stroke time testing will be performed. Contrary to this requirement, no
stroke time testing was performed on the valve. The inspectors also noted that the
condition was further aggravated by the licensees use of an OD to declare the valve
operable once the missed surveillance was initially identified. The licensee failed to
recognize the TS compliance aspect until prompted, repeatedly, by the inspectors.
The inspectors determined that the TS violation was more than minor using guidance in
Appendix B, of Inspection Manual Chapter 0612. The inspectors determined that the
failure to perform PMT on a safety related component could reasonably be viewed as a
precursor to a significant event. Using the Significance Determination Process (SDP),
this issue was evaluated as having very low risk significance (Green) since, although the
barrier integrity cornerstone was affected in that containment systems capability was not
demonstrated through TS required surveillance testing, subsequent testing
demonstrated that the system would have performed its intended safety function. This
violation is being treated as a Non-Cited Violation (NCV 50-440/02-08-01) consistent
with Section VI.A. of the NRC Enforcement Policy. This violation was entered in the
licensees corrective action system as CR 02-03939.
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors observed surveillance testing or reviewed test data for risk-significant
systems or components to assess compliance with TS, 10 CFR Part 50 Appendix B, and
licensee procedure requirements. The testing was also evaluated for consistency with
the USAR. The inspectors verified that the testing demonstrated that the systems were
ready to perform their intended safety functions. The inspectors reviewed whether test
control was properly coordinated with the control room and performed in the sequence
specified in the surveillance instruction, and if test equipment was properly calibrated
and installed to support the surveillance tests. The procedures reviewed are listed in the
attached List of Documents Reviewed. The specific surveillance activities assessed
included:
HPCS room cooler heat balance on October 28, 2002;
Visual inspection of safety related reactor water cleanup snubbers conducted
October 30, 2002;
C
Unit 1, Division 1 battery capacity performance testing conducted November 25,
18
2002;
C
Functional test of average power range monitoring B Channel performed
December 10, 2002; and
C
Standby Liquid Control B Pump and valve operability testing conducted
December 11, 2002.
b.
Findings
No findings of significance were identified noted.
1R23
Temporary Plant Modifications (71111.23)
a.
Inspection Scope
The inspectors reviewed the licensees approved Temporary Modification (TM) 1-02-009
which eliminated a locked in annunciator for the A Reactor Recirculation Pump motor
bearing oil level high alarm. The scope of this TM was to change the annunciator circuit
card jumper configuration. The inspectors reviewed the TM technical evaluation,
bearing oil level trends, and the associated alarm response instructions to verify pump
operability was maintained.
In addition, the inspectors reviewed a temporary repair of the Motor Feed Pump to stop
a leak on an access plug. The inspectors reviewed the planned repair and
considerations for foreign material exclusion as well as implementation of the repair.
b.
Findings
No findings of significance were identified noted.
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1
Plant Walkdowns and Radiation Work Permit Reviews
a.
Inspection Scope
The inspectors reviewed the radiological conditions of work areas within radiation areas
and high radiation areas (HRAs) in the radiologically restricted area to verify the
adequacy of radiological boundaries and postings. This included walkdowns of high and
locked high radiation area boundaries in the Auxiliary, Intermediate, Containment, and
Radwaste Buildings. The inspectors performed independent measurements of area
radiation levels and reviewed associated licensee controls to determine if the controls
(i.e., surveys, postings, and barricades) were adequate to meet the requirements of
10 CFR Part 20 and the licensees Technical Specifications (TSs). Radiation work
19
permits (RWPs) for jobs having significant radiological dose potential were reviewed for
protective clothing requirements and dosimetry requirements including alarm set points.
Radiological work planning was reviewed for potential airborne areas and engineering
controls for mitigation of airborne activity. Reactor coolant isotopic data was evaluated
for the presence of Neptunium-239, which is a predictor of other transuranic isotopes.
The licensee had no uptakes resulting in 50 millirem or greater committed effective dose
equivalent in 2002. Pre-job briefings were attended to verify that radiological conditions
were adequately discussed with workers, and that workers were aware of potential
radiological hazards and understood the actions required for electronic dosimeter
alarms.
The inspectors reviewed the licensees controls for high dose rate material that was
stored in the spent fuel pool and the licensees inventory of materials currently stored in
the spent fuel pool to verify that the licensee had implemented adequate measures to
prevent inadvertent personnel exposures.
b.
Findings
No findings of significance were identified.
.2
Problem Identification and Resolution
a.
Inspection Scope
The inspectors reviewed the licensees condition report (CR) database and corrective
action documentation from January 2002, through November 2002, to evaluate problem
identification and resolution in the areas of access control, radiological work planning,
job coverage, radiation worker performance, and radiation protection technician
performance. Self-assessments and audits of the radiation protection and chemistry
organizations were evaluated and cognizant licensee personnel were interviewed to
verify that problems were identified and entered into the corrective action program for
resolution. The inspectors reviewed these documents to assess the licensees ability to
identify repetitive problems, contributing causes, the extent of conditions, and to develop
corrective actions which will achieve lasting results.
b.
Findings
No findings of significance were identified.
.3
Job In-Progress Reviews
a.
Inspection Scope
The inspectors observed aspects of work activities that were being performed in areas
having significant dose potential in order to ensure that adequate radiological controls
had been implemented. The inspectors observed radiation protection preparations and
radiological controls for diving operations in the lower pool (spent fuel pool), and other
20
radiologically significant jobs. The inspectors reviewed engineering controls, radiological
postings, radiological boundary controls, radiation work permit requirements, radiation
monitoring locations, dosimetry placement, and attended pre-job briefings to verify that
radiological controls were effective in minimizing and tracking dose. The inspectors also
observed radiation worker performance to verify that the workers were complying with
radiological requirements and were demonstrating adequate radiological work practices.
b.
Findings
No findings of significance were identified.
.4
High Dose Rate, High Radiation Area, and Very High Radiation Area Controls
a.
Inspection Scope
The inspectors reviewed the licensees controls for HRAs and very high radiation areas
(VHRA) including the posting and control of these areas to verify the licensees
compliance with 10 CFR Part 20 and the sites TSs. Records of HRA/VHRA boundary
and posting surveillances were reviewed and general area walk-downs were performed
to verify their adequacy. Control of HRAs and VHRAs was discussed with radiation
protection management, and the inspectors accompanied radiation protection
technicians during a lock out of portions of containment in preparation for a potentially
radiologically significant work evolution involving traversing incore probes.
b.
Findings
No findings of significance were identified.
.5
Radiation Worker Performance
a.
Inspection Scope
The inspectors evaluated radiation worker performance by observing the use of low
dose waiting areas and proper use of protective clothing, based on RWP requirements.
Radiological conditions were discussed with radworkers to determine worker awareness
of significant radiological conditions and electronic dosimetry set points. Radiological
problem condition reports were reviewed to determine if any weaknesses in radiation
worker performance had been identified.
b.
Findings
No findings of significance were identified.
.6
Radiation Protection Technician Performance
21
a.
Inspection Scope
Radiation protection technician performance was evaluated with respect to radiological
work requirements. The inspectors observed job coverage, control of contamination and
exit boundaries during job evolutions, control of radworkers, and reviewed technician
response to radiological incidents. Radiological problem condition reports were
reviewed to determine if any technician errors had been identified.
b.
Findings
No findings of significance were identified.
2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls (71121.02)
.1
Job Site Inspections and ALARA Control
a.
Inspection Scope
The inspectors reviewed jobs being performed in areas of potentially elevated dose rates
and examined work sites in order to evaluate the licensees use of ALARA controls to
minimize radiological exposure. Job exposure estimates were reviewed and work areas
were surveyed to determine radiological conditions. The ALARA briefing documentation
including the use of engineering controls were evaluated for dose minimization
effectiveness. During job site walkdowns, radiation workers and supervisors were
observed to determine if low dose waiting areas were being used appropriately.
Equipment staging, availability of tools, and work crew size were evaluated to determine
the effectiveness of job supervision in dose minimization.
b.
Findings
No findings of significance were identified.
.2
Problem Identification and Resolution
a.
Inspection Scope
The inspectors reviewed audits, self-assessments, and CRs related to the ALARA
program including post job reviews of radiologically significant work to determine if
problems were identified and properly characterized, prioritized, and entered into the
corrective action program. ALARA packages and post job reviews were evaluated to
determine if radiological work problems/deficiencies had been identified, if adequate
safety evaluations were performed, and the problems were entered into the licensees
corrective action system.
b.
Findings
22
No findings of significance were identified.
2OS3 Radiation Monitoring Instrumentation (71121.03)
.1
Calibration of Radiological Instrumentation
a.
Inspection Scope
The inspectors reviewed calibration records for the year 2002 for those instruments
utilized for surveys of personnel prior to egress from the radiologically restricted area
and the protected area. In addition, calibration records and selected nuclear libraries for
the whole body counter were reviewed to verify that these instruments were calibrated
adequately, consistent with station procedures and industry standards. The inspectors
examined portable survey instruments in use during plant tours to verify that those
instruments designated ready for use had current calibrations, had been source
checked, were operable and were in good physical condition.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES (OA)
Cornerstones: Mitigating Systems, Occupational Radiation Safety, and Public
Radiation Safety
4OA1 Performance Indicator (PI) Verification (71151)
.1
Mitigating Systems PI Verification
a.
Inspection Scope
The inspectors reviewed reported second and third quarter performance indicators for
RHR system performance indicators for system unavailability using the definitions and
guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment
Indicator Guideline, revision 2. The inspectors reviewed station logs, CRs, TS logs, and
surveillance procedures to verify the accuracy of the licensees data submission.
b.
Findings
No findings of significance were identified.
.2
Occupational and Public Radiation Safety PI Verification
23
a.
Inspection Scope
The inspectors reviewed the licensees determination of performance indicators for the
occupational and public radiation safety cornerstones to verify that the licensee
accurately determined these performance indicators and had identified all occurrences
required. These indicators included the Occupational Exposure Control Effectiveness
and the Radiological Effluent TSs/Offsite Dose Calculation Manual Radiological Effluent
Occurrences. The inspectors reviewed CRs for the year 2002, quarterly offsite dose
calculations for radiological effluents for the previous 4 quarters and access control
transactions for the year 2002. During plant walkdowns (Sections 2OS1.1, 2OS1.4), the
inspectors also verified the adequacy of postings and controls for locked HRAs, which
contributed to the Occupational Exposure Control Effectiveness performance indicator.
The inspectors also reviewed the licensees reactor coolant system activity performance
indicator for the reactor safety cornerstone to verify that the information reported by
the licensee was accurate. The inspectors reviewed the licensees reactor coolant
sample results for maximum dose equivalent iodine-131, December 2001 through
November 2002, and the licensees sampling and analysis procedures. The inspectors
also observed a chemistry technician obtain and analyze a reactor coolant sample.
b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
.1
Evaluation of Industry Operating Experience
a.
Inspection Scope
The inspectors reviewed the licensees actions in response to selected NRC Information
Notices to verify that the licensee considered industry experience in plant operation.
The inspectors reviewed condition reports, procedures, and proposed modifications as
well as interviewed key plant personnel.
b.
Findings and Observations
The inspectors concluded that the licensee was evaluating NRC Information Notices for
relevance and entering the notice into the corrective action program when relevant. The
licensee took actions when appropriate. The inspectors observed that some of the
corrective actions require modifications; however, the licensee has not determined if
they will be effected during the upcoming refueling outage. No findings of significance
were identified.
.2
Foreign Material Exclusion (FME) Program
24
a.
Inspection Scope
The inspectors reviewed the licensees FME program. The inspectors reviewed program
documents, condition reports, and corrective action plans. Additionally, the inspectors
reviewed licensee staff compliance with and comprehension of program requirements by
reviewing zone 3 access point material accountability control logs, reviewing work
package material accountability control logs, and interviewing all levels of plant
personnel including, but not limited to, the maintenance manager, FME program
coordinator, plant operators, security officers, and maintenance workers.
b.
Findings and Observations
Based on direct observation and interviews, the inspectors concluded that zone 3 FME
controls were not consistently applied by plant personnel. The inspectors observations
were entered in the licensees corrective action program as CR 03-00045, Zone 3
Material Accountability Logging.
4OA3 Event Followup (71153)
.1
(Closed) URI 50-440/02-04-02: Interpretation of ASME Code NF3276.2(c) for Vertical
Risers. This item involved inspector identification of a specific case where the licensee
incorrectly applied the ASME Code. Although the licensee agreed with the inspectors
regarding the specific calculation, the licensee acknowledged that there were other
examples where they had similarly applied the Code. However, the licensee disagreed
that the Code was mis-applied; therefore, they planned to seek a Code interpretation.
This item had been left open to evaluate the outcome of the Code interpretation on the
licensee's calculations. However, as the item is contained in the licensee's corrective
action program, NRC had determined that it is not necessary to have the item remain
open. This item is closed.
.2
(Closed) Licensee Event Report (LER) 50-440/2002-001-00: Unplanned Automatic Scram During Main Turbine Mechanical Trip Weekly Testing. On September 22, 2002,
the plant experienced a turbine control valve fast closure reactor scram due to a turbine
trip which occurred during routine weekly turbine overspeed testing. The licensees
review determined that the turbine trip was caused by a failure of the turbine trip latch
mechanism to reset at the conclusion of the weekly test. Following the scram, the
licensee was unable to drain the scram discharge volume. Further investigation
revealed that a scram discharge volume drain valve stem coupling had failed, thus the
valve would not reopen when the scram was reset. Inspector response associated with
this event is documented in IR 50-440/2002-006. The inspectors reviewed the LER.
The inspectors identified that the licensees abstract text incorrectly stated that the
scram discharge volume drain valve failed to close but the licensee correctly
characterized the event in the body of the LER. The licensee informed the inspectors a
supplement would be submitted to correct the error. This LER is closed.
.3
High Pressure Core Spray (HPCS) Pump Failure to Start
25
A self-revealed apparent violation of TS 5.4 occurred when the HPCS pump failed to
start during a surveillance test. Troubleshooting revealed that contacts required for
starting the HPCS pump were misaligned. The licensee performed one PMT and two
inspections of the circuit breaker that would have detected the misalignment of contacts
had the procedure been properly followed. The NRC assessed this finding in
accordance with Inspection Manual Chapter 0609 and made a preliminary determination
that it was an issue with some increased importance to safety.
On October 23, 2002, the HPCS pump failed to start during routine testing of the HPCS
room cooler heat exchanger. Subsequent troubleshooting revealed that a set of
contacts within the circuit breaker cabinet that provide a close permissive signal were
not fully engaged, thus preventing remote or automatic start of the HPCS pump. When
the HPCS breaker is inserted into its enclosure, the breaker contacts a lever arm which
raises an actuator arm to rotate a set of contacts known as a cell switch. The cell switch
rotates 90o as the breaker is racked into its enclosure. When fully racked in, one of the
contacts on the cell switch provides a permissive signal for breaker closure. In the as
found condition, the actuating arm was too long which resulted in a condition in which
the cell switch did not achieve full contact engagement. While this permitted several
successful starts of the HPCS pump, the as found condition was susceptible to, and
finally succumbed to, minor changes in tolerances that resulted in incomplete
engagement of the close permissive contacts. Licensee procedures for cell switch
inspection stipulated that normally open contacts be in the flat horizontal position prior to
breaker installation. In the as found condition, these contacts were not in the flat,
horizontal position. In order to achieve this alignment, the licensee was required to
remove 3/8 of an inch from the actuating arm. Both the licensees root cause evaluation
and the inspectors review of the event concluded that given the amount of material
removed from the actuating arm, the as found misalignment of the contacts could not be
attributed to normal wear and tear of the breaker. The HPCS system was subsequently
declared operable on October 24, 2002.
The licensees root cause investigation identified several opportunities to prevent this
occurrence. In 1994, the licensee replaced the HPCS breaker. Post-installation, the
licensees inspections failed to identify the contact misalignment. Subsequent
inspections of the cell switch in 1998 and 2002 also failed to identify the poor alignment
of the cell switch. In addition, the breaker failed a PMT in 1998; however, the licensee
was not able to ascertain the cause of this failure and subsequently successfully tested
the breaker.
The inspectors evaluated this finding under the SDP. The inspectors concluded that this
finding directly affects the mitigating system cornerstone objective of safety system
availability. The inspectors evaluated the finding under phase 1 of the SDP process and
determined a phase 2 evaluation was needed. The inspectors based this conclusion on
the loss of the HPCS safety function since in the as found condition HPCS would not
start automatically or manually from the control room. The inspectors concluded that no
specific event could be used to establish the time HPCS became inoperable. Therefore,
the HPCS system was considered to be unavailable for a duration of 23 days. This was
based on the HPCS system being unavailable from August 28 to October 23, 2002, the
26
time from last successful surveillance until time of discovery. However, the plant was in
an outage during this period from September 23 through October 3, 2002, and HPCS
availability was not required. Using the T/2 approach, the inspectors considered the
HPCS system to be unavailable for the total time period minus the outage time divided
by 2.
The initial Phase 2 risk assessment characterized this finding as Yellow using the
benchmarked site specific Risk-Informed Inspection Notebook. However, a Phase 3
analysis performed by the regional Senior Reactor Analyst (SRA) determined the issue
was a White finding. The SRA reviewed the SDP Summary Report which compared the
Risk-Informed Inspection Notebook worksheets against the licensees updated
probabilistic risk assessment (PRA). This process compared the SDP results for a
duration of greater than 30 days against the licensees PRA results for a one year
duration. The SRA determined that the Risk-Informed Notebook results provided a one
order of magnitude greater risk significance than both the licensees PRA and the
Standardized Plant Analysis of Risk (SPAR) model.
Technical Specification 5.4 states, in part, that procedures shall be established,
implemented and maintained as recommended in Regulatory Guide 1.33. Regulatory
Guide 1.33 recommended procedures for performing maintenance that can affect
performance of safety related equipment. Contrary to this requirement, the licensee
failed to follow the procedure for breaker installation and inspection. Specifically, the
licensees procedure, GEI-0135, ABB Power Circuit Breakers 5 KV Types 5HK250 and
5HK350 Maintenance, required inspection to confirm that open contacts are in the flat,
horizontal position. While the procedure allows for deviation from the flat horizontal
alignment, clear make/break of the contacts must be observed. The physical
configuration of the cell switch prevents observation of contact make/break; therefore,
the open contacts must be in the flat, horizontal position to comply with the procedure.
In the as found condition, the cell switch was significantly out of the flat horizontal
condition. Pending completion of a final safety significance review, this issue is an
Apparent Violation (AV) (AVI 50-440/02-08-02). The licensee has entered this
apparent violation into its corrective action program as CR 02-03972.
4OA6 Meetings
.1
Exit Meeting
The inspectors presented the inspection results to Mr. T. Rausch, General Manager and
other members of licensee management at the conclusion of the inspection on
January 9, 2003. The inspectors asked the licensee whether any materials examined
during the inspection should be considered proprietary. No proprietary information was
identified
.2
Interim Exit Meetings
Interim exits were conducted for:
Biennial Operator Requalification Program Inspection with Mr. T. Rausch on
27
November 1, 2002;
Heat Sink Inspection with W. Kanda and T. Rausch on November 7, 2002;
Licensed Operator Requalification 71111.11B with Mr. R. Gemberling, Operations
Requalification Training Lead, on December 17, 2002, via telephone;
Access Control, ALARA, Instrumentation and performance indicator verification with
Mr. T. Lentz and Mr. K. Ostrowski on October 17 and December 12, 2002; and
Maintenance Rule Implementation - Periodic Evaluation with T. Rausch on
December 19, 2002.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by the
licensee and was a violation of NRC requirements which met the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCV.
The use of the minor work order was contrary to the requirements of licensee procedure
NOP-WM-9001, Minor Work Order, which did not allow packing adjustments on safety
related motor operated valves. Because a minor work order was used, SRO review of
the work package was not conducted. Section 4A07 of this report documents the
licensee identified green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, for failure to use documented instructions, procedures, or
drawings, of a type appropriate to the circumstances. After the packing adjustment, no
post-maintenance testing was performed.
28
KEY POINTS OF CONTACT
Licensee
W. Kanda, Vice President-Nuclear
T. Rausch, General Manager, Nuclear Power Plant Department
D. Bowen, Licensing
R. Coad, Radiation Protection Manager
R. Collings, Training Manager
W. Colvin, Perry Maintenance Rule Coordinator
F. Eichenlaub, Plant Performance Engineer
R. Gemberling, Licensed Operator Requalification Training Lead
R. Hayes, Chemistry Manager
V. Higaki, Manager, Regulatory Affairs
R. Kearny, Operations Manager
T. Lentz, Acting Director Nuclear Engineering
L. Lindrose, Supervisor Nuclear Security Operation
B. Luthanen, Compliance Engineer
T. Mahon, Site Protection Section Manager
J. McHugh, Operations Training Unit Superintendent
K. Meade, Supervisor, Compliance
K. Ostrowski, Director, Nuclear Maintenance
J. Palinkas, Supervisor, Security Systems and Administration
B. Panfil, Simulator Support
D. Phillips, Manager, Plant Engineering
T. Rausch, General Manager, Nuclear Power Plant Department
M. Rossi, Performance Engineer
K. Russell, Compliance Engineer - Nuclear Licensing
S. Sovizal, Supervisor, Security Training
R. Strohl, Superintendent, Plant Operations
L. VanDerHorst, Health Physics Supervisor
29
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-440/02-08-01
Failure to Perform TS Required Testing
50-440/02-08-02
High Pressure Core Spray Pump Failure to Start
50-440/2002-001-00
LER
Unplanned Automatic Scram During Main Turbine Mechanical
Trip Weekly Testing
Closed
50-440/02-04-02
Interpretation of ASME Code NF3276.2(c) for Vertical Risers
50-440/02-08-01
Failure to Perform TS Required Testing
50-440/2002-001-00
LER
Unplanned Automatic Scram During Main Turbine Mechanical
Trip Weekly Testing
30
LIST OF ACRONYMS USED
As Low As Reasonably Achievable
American Society of Mechanical Engineers
CR
Condition Report
Diesel Generator
Electrical Power Research Institute
LER
Licensee Event Report
Licensed Operator Requalification Training
NEI
Nuclear Energy Institute
Non-Cited Violation
NEI
Nuclear Energy Institute
NRC
Nuclear Regulatory Commission
Operator Workaround
PEI
Perry Emergency Instruction
Performance Indicator
Post-maintenance testing
Reactor Core Isolation Cooling
Reactor Operator
Radiation Work Permit
Significance Determination Process
Standardized Plant Analysis of Risk
SR
Surveillance Requirement
Senior Reactor Analyst
Senior Reactor Operator
Structure, System & Component
SVI
Surveillance Instruction
TM
TS
Technical Specification
Unresolved Item
Updated Safety Analysis Report
Very High Radiation Area
VLI
Valve Lineup Instruction
31
LIST OF DOCUMENTS REVIEWED
1R01
Adverse Weather
PTI-GEN-P0026
Preparations For Winter Weather
Rev. 0
PTI-GEN-P0027
Cold Weather Support System Startup
Rev. 0
ONI-R36-2
Extreme Cold Weather
Rev. 0
SOI-R36
Heat Trace and Freeze Protection System
Rev. 5
ICI-C-R36-1
Heat Tracing and Freeze Protection Panels
Rev. 2
Operation and Maintenance Manual Heat Trace
Control System Supplied By Nelson Electric
Model 3600 Series Modular Temperature
Control System
Rev. 3
ONI-P40
Rev. 1
1R04
Equipment Alignment
Control Room Emergency Recirculation
VLI-M25/26
Control Room HVAC and Emergency
Recirculation System
Rev. 6
SDM-M25/26
Control Room HVAC and Recircluation System
Rev. 5
CR 01-0247
M25 Inlet A Train Modification
January 22, 2001
CR 01-0139
M25/26 Compensatory Actions Remain Open
with No Work Planned
January 13, 2001
VLI-R44
Division 1 and 2 Diesel Generator Starting Air
System(unit 1)
Rev. 4
VLI-R45
Division 1 and 2 Diesel Generator Fuel Oil
System
Rev. 4
VLI-R46
Division 1 and 2 Diesel Generator Jacket Water
Systems
Rev. 3
VLI-R47
Division 1 and 2 Diesel Generator Lube Oil
Rev. 4
VLI-R48
Division 1 and 2 Diesel Generator Exhaust,
Intake and Crankcase Systems
Rev. 4
302-0351-00000
Standby Diesel Generator Starting Air
Rev. W
302-0352-00000
Standby Diesel Generator Fuel Oil System
Rev. DD
32
302-0354-00000
Standby Diesel Generator Jacket Water
Rev. R
302-0353-00000
Standby Diesel Generator Lube Oil
Rev. R
302-0355-00000
HPCS and Standby Diesel Generator Exhaust,
Intake and Crankcase
Rev. R
VLI-E22A
High Pressure Core Spray (Unit 1)
Rev. 5
VLI-E51
Reactor Core Isolation Cooling System
Rev. 3
VLI-P42
Emergency Closed Cooling System
Rev. 7
CR 00-3859
Conflict on Full Performance Credit for SVI-
P42T2001
December 13, 2000
CR 01-1715
ECC-B Surge Tank Valve 1P42-F0668 Out of
Position
April 2, 2001
1R05
Fire Protection
Drawing E-023-007
Fire Protection Evaluation - Units 1 and 2
Control Complex Plan - El. 599'-0"
Rev. 11
Drawing E-023-008
Fire Protection Evaluation - Units 1 and 2
Intermediate and Fuel Handling Buildings Plan -
El. 599'-0"
Rev. 11
Drawing E-023-011
Fire Protection Evaluation - Units 1 and 2
Control Complex and Diesel Generator Building
Plan - El. 620'-6"
Rev. 11
Drawing E-023-012
Fire Protection Evaluation - Units 1 and 2
Intermediate and Fuel Handling Buildings Plan -
El. 620'-6"
Rev. 11
Drawing E-023-015
Fire Protection Evaluation - Units 1 and 2
Control Complex and Diesel Generator Building
Roof Plan - Elevations 638'-6" and 646'-6"
Rev. 11
Drawing E-023-016
Fire Protection Evaluation - Units 1 and 2
Intermediate and Fuel Handling Buildings Plan -
El. 639'-6", 654'-6"
Rev. 11
Drawing E-023-024
Fire Protection Evaluation - Units 1 and 2
Intermediate and Fuel Handling Buildings Plan -
El. 682'-6"
Rev. 11
USAR Section
9A.4.2.1.7
Fire Zone 1AB-1g
33
USAR Section
9A.4.2.1.10
Fire Zone 1AB-3b
USAR Section
9A.4.3.2
Fire Zone IB-2
USAR Section
9A.4.3.3
Fire Zone IB-3
USAR Section
9A.4.3.4
Fire Zone IB-4
USAR Section
9A.4.3.5
Fire Zone IB-5
USAR Section
9A.4.4.3.1.3
Fire Area 1CC-3c
USAR Section
9A.4.4.3.1.2
Fire Area 1CC-3b
USAR Section
9A.4.5.1.2
Fire Area 1DG-1b
USAR Section
9A.4.4.2
Unit 1 and 2 Fire Areas, Floor 2 (CC-2)
USAR Section
9A.4.4.4
Fire Areas, Floor 4
FPI-1AB
Pre-Fire Plan Instruction, Auxiliary Building
Rev. 0
1R07
Biennial Review of Heat Sink Performance
Calculation E12-89
Required ESW Flow for the RHR Hxs
Revision 3
Calculation E12-98
Residual Heat Removal B/D Performance Test
Results Evaluation - 11/17/99
Revision 0
Calculation E12-98
Residual Heat Removal B/D Performance Test
Results Evaluation - 11/29/2000
Revision 1
P42-039
Design Basis Heat Load & Required ESW Flow
to the ECC Hxs
Revision 2
P42-43
ECC "A" HX Performance Test Evaluation
9/9/98
Revision 1
P42-45
ECC "A" HX Performance Test Evaluation
9/14/99
Revision 0
34
Inspection Report for 1 E12B001B/D - RHR B/D
April 6, 1999
Inspection Report for 1 P42-B001A - P42 A HX
September 28,
1997
GEK-90389
February 1984
GAI File Number 96-
035-0-01
June 16, 1978
CR 00-3557
Potential Error Calculation Hoff Number in
PROTO-HX and PROTO-FLO Models
November 15, 2000
CR 01-1453
Potential Error in Design Heat Load for ECC HX
March 15, 2001
CR 01-2442
Degraded ESW Flow Through Division 2 DG HX
June 13, 2001
CR 01-3710
Silt Removal Criteria for SWPH
October 22, 2001
CR 01-3711
Silt Removal Criteria for ESWPH
October 22, 2001
CR 02-00151
Results Obtained From Computer Program
(PROTO-HX) Do Not Match Spec Sheet
January, 17, 2002
CR 02-00326
PA02-03 Audit Finding, OD Not Appropriately
Utilized on ESW
January 31, 2002
CR 02-00599
Latent Issues, ESW Piping Analysis
February 28, 2002
CR 02-01004
Emergency Service Water B Flow Less Than
7300
April 3, 2002
CR 02-01217
ESWPH & Intake Tunnel Silt Removal
April 22, 2002
CR 02-01230
Modeling Error in DI-229 to Support Perform
April 24, 2002
CR 02-01282
Request for Assistance for Operator Training
April 29, 2002
CR 02-1633
Documentation of Silt Inspection of ESWPH
October 22, 2001
CR 02-03180
Emergency Closed Cooling System Calculation
Heat Load Discrepancy
September 10,
2002
CR 02-03220
Timeliness in the Identification and Processing
of CRS
September 12,
2002
CR 02-04163
SA 538-NQA-2002: Timely Resolution of
Degraded Condition (ESW/P45)
November 4, 2002
CR 02-2168
Foreign Material Found in ESWPH Forebay;
July 1, 2002
1R11
Licensed Operator Requalification
35
Licensee Event
Report (LER)
2001-01
Manual Scram Due to Decreasing Main
Condenser Vacuum and Invalid Division 2 and 3
ECCS Actuations
June 14, 2001
LER 2001-03
Loss of Feedwater Scram and Specified System
Actuations Including ECCS [Emergency Core
Cooling System] Injections
August 20, 2001
LER 2001-05-01
Automatic RPV [Reactor Pressure Vessel] Level
SCRAM, Specified Systems Activations and
Inoperability of the Division 3 Diesel Generator
February 13, 2002
Examination Security Agreement Form 6413
Revision A
NRC Inspection Report 50/440-00-14
January 18, 2001
NRC Inspection Report 50/440-01-04
April 19, 2001
NRC Inspection Report 50/440-01-08
June 5, 2001
NRC Inspection Report 50/440-01-10
September 5, 2001
NRC Inspection Report 50/440-01-11
August 22, 2001
NRC Inspection Report 50/440-01-12
October 19, 2001
NRC Inspection Report 50/440-01-13
December 12, 2001
NRC Inspection Report 50/440-01-15
January 30, 2002
NRC Inspection Report 50/440-01-16
March 18, 2002
NRC Inspection Report 50/440-02-02
April 17, 2002
NRC Inspection Report 50/440-02-05
July 30, 2002
PTSG-07
Simulator Scenario Guide Preparation, Review
and Approval
Revision 0
PTSG-15
Performance Evaluation Preparation, Review,
Revision, Approval and Administration
Revision 0
TMA-4106
Simulator Scenario Guide Preparation, Review,
Revision and Approval
Revision 3
TMA-4110
Simulator Training Administration
Revision 3
TMA-4206
Control Room Simulator Configuration
Management Program
Revision 4
TMG-1007
Implementation of Training
Revision 5
TMP-2002
Licensed Operator Requalification Program
Revision
PAP-0201
Conduct of Operations
Revision 10
36
DG-13
Simulator Processes and Programs
Revision 0
OTG-5;
Continuing Training Program Administration
Revision 6
EDG-97-003
Review of Operating Instructions for
USAR/Design Basis Impact
Revision 2
FENOC; Expectations Handbook - Operations
Section
Revision 3
2002 Cycle Focus Items, Specifically for Staff
Crew #1 plus Samples for All Other Crews
Medical Evaluation Records; Various (3 RO,
6 SRO)
Maintenance of Active License Records;
Simulator Work Order Summary - Open Items
Simulator Work Order Summary - Closed Items
Justification for Using the Perry Training
Simulator Cycle 8 Core Model During Cycle 9
License Operator Training Programs
November 5, 2001
ANSI Appendix B Transient Test for 2002
(sample)
Simulator Certification Test - Malfunction Test,
(sample), pre 1998
Simulator Certification Test - Normal Plant
Evolutions, (sample), 1996 - 1999
Licensed Operator Requalification Exam
Sample Plans - 2002; Week 1- 7
Simulator Examination Summary Sheets, for
Cycle 2, 2001, Cycle 5, 2001 (2001 Annual
Operating Exam), Cycle 8, 2002, and Annual
Operating Exam Conducted October 29, 2002
Remediation Documentation for Cycle 2, 2001,
Cycle 5, 2001 (2001 Annual Operating Exam),
and Cycle 8, 2002
Attendance Checklists For Cycle 2, 2001,
Cycle 5, 2001, and Cycle 8, 2002
Dynamic Simulator Individual Evaluation Sheets
For Cycle 2, 2001, Cycle 5, 2001 (2001 Annual
Operating Exam), and Cycle 8, 2002
37
Master Licensed Operator Requalification
Schedule From January 10, 2001, to
December 12, 2002
Written Test ID Number 02-001, RO [Reactor
Operator] Part B Requalification Exam
October, 14, 2002
Written Test ID Number 02-002, SRO [Senior
Reactor Operator] Part B Requalification Exam
October, 14, 2002
Written Test ID Number 02-003, RO [Reactor
Operator] Part B Requalification Exam
October, 21, 2002
Written Test ID Number 02-035, RO [Reactor
Operator] Part A Requalification Exam
October, 14, 2002
Written Test ID Number 02-036, SRO [Senior
Reactor Operator] Part A Requalification Exam
October, 14, 2002
Scenario Set OT-3070-PSC5
Revision 3
Scenario Set OT-3070-RP2C
Revision 2
Scenario Set OT-3070-PC3A
Revision 4
JPM OT-3701-
E51_02
Manually Startup RCIC [reactor core isolation
cooling] From Standby Readiness
Revision 0
JPM OT-3701-
T23_01
Open Turbine Building Roll Up Door North
Revision 0
JPM OT-3701-
C41_08
Inject Into The Reactor Pressure Vessel Using
Alternate Boron Injection
Revision 0
JPM OT-3701-
E12_10
Lineup In-plant Portion of Residual Heat
Removal B Flood Alternate Injection
Revision 0
1R12 Maintenance Effectiveness
CR 01-2257
Relief Valve Removed from 1P45F543B Fails
As-Found Set Pressure Testing
May 17, 2001
CR 01-2159
Valve Removed from 1P45F31A Failed As-
found Set Pressure Testing
May 8, 2001
CR 01-1821
Maintenance Rule Evaluation Required on Div
3ESW Flow Indication
April 11, 2001
CR 01-1244
Relief Valve 1P54F0520 Failed As-left Seat
Leakage Test
May 9, 2001
CR 01-1335
Relief Valve 1P54F0517 Fails As-found Lift Test
May 9,2001
38
CR 02-00326
PA02-03 Audit Finding, OD not Appropriately
Utilized on ESW
January 31, 2002
CR 01-2257
Relief Valve removed from 1P45F543B Fails
As-Found Set Pressure Testing
May, 17 2002
CR 02-00534
Maintenance Rule Evaluation of 1E12R602B
February 19, 2002
Maintenance Rule Functions, Performance
Criteria and Classifications
Rev 5.04
PAP-1125
Monitoring the Effectiveness of Maintenance
Program Plan
Rev. 6
PYBP-PES-0001
Maintenance Rule Reference Guide
Revision 12
PAP-1125
Monitoring the Effectiveness of Maintenance
Program Plan
Revision 6
Calculation No.
SM-05
System Notebook - Residual Heat Removal
(RHR) System, E12
Revision 2
Calculation No.
SM-08
System Notebook - Reactor Core Isolation
Cooling (RCIC), E51
Revision 2
Calculation No.
SM-07
System Notebook - High Pressure Core Spray
(HPCS), E22
Revision 2
Calculation No.
G41-42
Fuel Handling Building Pools Heat-up Analysis
Revision 6
Calculation No.
SM-20
Standby Diesel Generator (DG) System, R43,
High Pressure Core Spray Diesel Generator
System, E22B
Revision 0
Calculation No.
G41-38
Time-to-Boil Water in Reactor Vessel and Upper
Pools During Refueling
Revision 6
Calculation No.
RXE-0001/00
RF08 Decay Heat Calculation
August 18, 2000
Calculation No.
6.16
Determination of Level 1 Probabilistic Safety
Assessment Safety Significant System,
Structures, and Components (SSCs) for the
Perry Nuclear Power Plant Maintenance Rule
July 1, 1999
CR 00-1639
The Diesel Driven Fire Pump Has a Missing Bolt
Around the Turbo Charger
May 25, 2000
CR 00-2267
Control Room Chiller was Not Running, There
Were No Alarms That Indicated the Chiller Had
Tripped
July 19, 2000
39
CR 00-2516
While Attempting to Start the B Combustible
Gas Mixing Compressor for SVI M51-T2003B,
the Switch was Taken to Start and the
Compressor Did Not Start
August 20, 2000
CR 00-2531
While Performing SVI-G43-T1307 Step 5.1.18,
As Found Data was Out of the Allowable
Value
August 21, 2000
CR 01-1483
M23C0002A Fan Failed to Start in the Division
1 Loss of Offsite Power /Loss of Coolant
Accident Fan Start Logic
March 17, 2001
CR 00-3857
Diesel Driven Emergency Fire Pump Failed to
Start
December 12, 2000
CR 01-1711
Broken Fuse Block for Gas Mixing
Compressor A
April 1, 2001
CR 00-3839
Fuel Function (a)(1) - Goal Setting and Goal
Monitoring for the Fuel Function
December 11, 2000
CR 02-02647
Maintenance Rule Structure Monitoring -
PY-C-02-03
August 7, 2002
CR 02-02663
RFA - Maintenance Rule Program
Enhancements -PY-C-02-03
August 9, 2002
CR 00-1473
System Flow on Fan 1M15-C0001A was
Outside the Nominal Flow Band
May 15, 2000
CR 00-1549
During Normal Operation of the Power Plant,
Received an Unexpected Half Main Steam line
Isolation Signal From the Division 2 Leak
Detection System
May 22, 2000
Maintenance Rule Monitoring Program Periodic
Assessment Report of Maintenance
Effectiveness for Operating Cycle 8 (May 2,
1999 - March 21, 2001)
June 17, 2002
Maintenance Rule Monitoring Program Periodic
Assessment Report of Maintenance
Effectiveness for Operating Cycle 7
(October 20, 1997 - May 2, 1999)
July 26, 2000
Perry Nuclear Power Plant System Health
Report - Third Quarter 2002
Oversight and Process Improvement Nuclear
Quality Assessment - Maintenance Rule and
System Health; (July 17, 2002 - August 9, 2002)
40
List of Condition Reports and Work Orders for
Diesel Generator, High Pressure Core Spray,
Residual Heat Removal System, and Reactor
Core Isolation Cooling (Oct. 1999 - Oct. 2000)
List of Condition Reports for Foreign Material
Exclusion Problems (January 2000 -
December 2002)
December 18, 2002
List of Functional Failures and Maintenance
Preventable Functional Failures
December 17, 2002
Memorandum (Maintenance Rule Expert Panel
Meetings: August 4, 1999, September 29,
1999, July 26, 2000, July 5, 2000, July 7, 2000,
July 12, 2000, July 25, 2000, September 13,
2000, November 22, 2000, January 10, 2000,
January 10, 2001 (Panel # 183 & # 184),
February 7, 2001, June 13, 2001 (Panel #186 &
- 187 & #188), February 22, 2002 (Panel #195 &
- 196), June 10, 2002, March 6, 2002, April 10,
2002)
Maintenance Rule Functions, Performance
Criteria, and Classifications
May 15, 2002
List of Current (a)(1) Maintenance Rule
Systems
November 20, 2002
CR Issued as a Result of Inspection
CR 02-04837
Perry Maintenance Rule Program Has a
Vulnerability to Not Comprehensively Monitor
Failures and Conditions to Demonstrate That
the Performance of Systems, Structures, and
Components were Effectively Controlled
Through the Performance of Appropriate
Maintenance
December 19, 2002
CR 02-04843
Question on the Adequacy of the
Documentation for Revising the Risk
Significance of the Hydrogen Ignition System
From High to Low in Calculation 6.17
December 19, 2002
41
CR 02-03555
Corrective Action Number 11; Review the
Additional Information in Condition Report
02-04837, NRC Maintenance Rule Inspector
Identified Program Vulnerability, to Properly
Consider the Full Extent of the Condition
Report 02-03555 Corrective Action to
Comprehensively Monitor Failures and
Conditions
December 23, 2002
1R13
Maintenance Risk Assessments and Emergent Work Control
PAP-1924
On-line Safety and Configuration Risk
Management
Rev. 2
PDB-C0011
PSA Presolved Configurations for On-line Risk
Management
Rev. 2
Div. 2 Allowed Outage Time Overview
Week 4, Period 8 Forecast Risk Profile
November 18, 2002
Week 6, Period 8 Forecast Risk Profile
December 2, 2002
Week 7, Period 8 Forecast Risk Profile
December 9, 2002
1R15
Operability Evaluations
CR 02-03831
Containment Equipment Drain Sump Cooler
Potentially Undersized
November 15, 2002
SDM G61
Liquid Radwaste Sumps System
Rev. 4
DWG 302-0672-
00000
Reactor Water Cleanup System
Rev. DD
DWG D-911-601
Reactor Building Drains
Rev. J
P1141
Break Exclusion Subsystem 1G61G03A
Penetrations P-417
October 14, 1983
P0929
Recalculate Fatigue Usage Factor Using a
Code Allowed Fatigue Strength Reduction
Factor
August 8, 1985
Containment Systems
CR 02-03829
Minor Maintenance performed on Safety
Related Equipment
October 9, 2002
Main Steam Shutoff Valves
Inservice Testing Program
42
TAI-1102-2
Inservice Testing of ASME Section XI Valves
Rev. 11
PAP-1101
Inservice Testing of Pumps and Valves
Rev. 5
CR 02-04028
October, 28, 2002
CR 02-04076
SP810-20-016
Mechanical Equipment Qualification Review File
for V522F/A41AD & V522J/A41AJ Vent Valves
Rev. 2
Drawing B 022-
0022-00000
Environmental Conditions for Containment
Building
Rev. J
CR 02-04605
Surveillance Report, Control Rod Scram Time
Test Results
December 11, 2002
Marathon S Control Blade, Nuclear Impact
Analysis
December 5, 2002
1R16 Operator Workarounds
Operator Work Around Log
December 23, 2002
CR 01-3615
Operator Work Around Performance Indicator
Goal Setting
October, 12, 2001
1R19
Post-Maintenance Testing
Main Steam Shutoff Valves
Inservice Testing Program
TAI-1102-2
Inservice Testing of ASME Section XI Valves
Rev. 11
PAP-1101
Inservice Testing of Pumps and Valves
Rev. 5
WO 02-011347-
000
October 27, 2002
CR 02-03952
RFA-Is is Acceptable to Close 1N11F0020B
<20 Percent Power with 1B21F0028B Closed
November 22, 2002
WO 02-010369-
000
Scram Discharge Volume First Drain
September 27, 2002
PIF 98-0125
January 22, 1998
CR 01-2441
Reactor Feed Booster Pump A Start Failure
June 13, 2001
PIF 95-1097
May 27, 1995
43
CR 94-553
May 20, 1994
CR 85-129
August 24, 1985
CR 85-117
August 8, 1985
CR 02-03972
HPCS Pump Failed to Start
October 23, 2002
CR 02-03976
Cell Switch for Breaker Found Out of
Adjustment
October 23, 2002
Troubleshooting Report
October 24, 2002
PMI-0030
Maintenance of Limitorque Valve Operators
Rev. 5
SVI-C41T2001A
Standby Liquid Control A Pump and Valve
Operability Test
November 7, 2002
SDM C41
Standby Liquid Control System
Rev. 8
SVI-E12-T2002
RHR B Pump and Valve Operability Test
December 12, 2002
GEI-0128
Installation and Removal of Diagnostic Test
Equipment on Motor Operated Valves
Rev. 3
SDM-E12
Residual Heat Removal System
Rev. 9
WO 00-002884-
000
Replace Capacitor C25 on Master Trip Unit for
RHR C Suction Pressure - Low Trip
December 11, 2002
1R22
Surveillance Testing
PTI-M39-P0002
High Pressure Core Spray Pump Room Cooler
Performance
Rev. 1
WO 02-003627-
000
High Pressure Core Spray Pump Room Cooler
Performance Testing
November 28, 2002
SDM M39
Pump Room Cooling System
Rev. 3
SVI-L51-T2000
Augmented Visual Inspection/Examination of
Safety-Related Snubbers
Rev. 5
SVI-R42-T5215
Performance Test of Battery Capacity -
Division 1 (Unit 1)
Rev. 6
USAR Section
8.3.2
DC Power Systems
SVI-C41-T2001-B
Standby Liquid Control B Pump and Valve
Operability Test
Rev. 3
USAR Section
9.3.5
Standby Liquid Control (SLC) System
44
Union Pump Company Vendor Manual 5715M
CR 02-04715
Flow and Pressure Difficulties While Performing
SVI-C41-T2001B
December 11, 2002
SVI-C51-T0027B
APRM B Channel Functional for 1C51-K605B
Rev. 6
1R23 Temporary Modification Control
ARI-H13-P680-4
Recirc Flow Control
Rev. 5
TM 1-02-009
Temporary Modification Technical Evaluation
Rev. 0
GMI-0095
Instructions for the Use and Control of ON line
Leak Sealing
Rev. 2
PAP-1402
Temporary Modification Control
Rev. 10
CR 02-04434
Leak Sealing Device Installation on Motor Feed
Pump
November 21, 2002
CR 02-02334
Water Leak on the Motor Feed Pump
July 16, 2002
02-01503
10 CFR 50.59 Screen, Install Leak Seal Device
on MDFP Casings Pipe Plug
November 13, 2002
CR 02-04270
Installation of Leak Sealing Device on Motor
Feed Pump Casing
November 12, 2002
2OS1 Access control to Radiologically significant Areas
2OS2 ALARA Planning and Controls
RWP 02-0056
ALARA Work Package, FPCC Holding Pump
Room, Filter Replacement
September 4, 2002
PJE 02-0048
ALARA Post Job Evaluation for RWP 02-0056
October 15, 2002
RWP 02-0021
ALARA Work Package, Perform Work Relative
to G33/G36 Outage Activities
Revision 0
PJE 02-0002
ALARA Post Job Evaluation, G33/G36 System
Outage
January 16, 2002
RWP 02-0027
ALARA Work Package, Condenser Inleakage
Testing
Revision 0
PJE 02-0001
Condenser Water Boxes
January 22, 2002
RWP 02-0066
ALARA Work Package, Leak Recovery/Repair
Revision 2
PJE 02-0047
ALARA Post Job Evaluation, Secure Flange
Leak
October 15, 2002
45
RWP 02-0052
ALARA Work Package, In Leakage Testing LP
Condenser C Waterbox
Revision 0
PJE 02-0003
ALARA Post Job Evaluation, LP Condenser C
Waterbox
June 3, 2002
RWP 02-0048
ALARA Work Package, Condensate Filter Septa
Remove/Replace
Revision 0
PJE 02-0004
ALARA Post Job Evaluation, Condensate Filter
Septa Remove/Replace
August 12, 2002
PJE 02-052
ALARA Post Job Evaluation, Replace 1G33
F0503 Relief Valve
November 26, 2002
PJE 02-051
ALARA Post Job Evaluation, Repairs to Leaking
Flange on 1G331B0001B
November 19, 2002
RWP 02-0151
IFTS Diving Activities
October 15, 2002
02-008371-000
Work Order: Fuel Transfer Equipment
October 15, 2002
467RPS2002
Dosimetry Self Assessment
August 21 through
September 30, 2002
466RPS2002
Locked High Radiation Area Self Assessment
Plan
June 10, 2002
PA 02-01
Radiation Protection Program Audit
February 27, 2002
P35-F018
Gamma Spectroscopy Analysis
October 17, 2002
Trend Chart
Neptunium 239 in Reactor Water
September 5
through October 10,
2002
Trend Chart
Dose Equivalent Iodine in Reactor Water
December 23, 2001
through October 13,
2002
HPI-D0004
Surveillance of High Radiation Area Barricades
Revision 2
PAP-0123
Control of Locked High Radiation Areas
Revision 6
HPI-D0004
Locked High Radiation Area Barricade
Operational Surveillance
August 27, 2002
HPI-D0004
Locked High Radiation Area Barricade
Operational Surveillance
August 29, 2002
HPI-D0004
High Radiation Area Barricade Surveillance
August 5 through
October 5, 2002
46
FTI-A0017
Non-Special Nuclear Material Pool Inventory
Mechanism
Revision 0
FTI-A0017
Pool Inventory Log
Revision 0
Reactor Coolant System Dose Equivalent Iodine
June 2001 through
September 2002
RPI-0504
Radiologically Restricted Area Diving Program
Revision 2
02-03113
G41 Post Filter Removal
September 5, 2002
02-03581
AMP 100 Survey Meter Failed While In Use
October 1, 2002
02-03612
Upper IFTS Pool Dose Rates Relative to Debris
in Pool
October 2, 2002
02-03652
Failed Meter
October 4, 2002
02-03662
Meter Failed During Survey
October 6, 2002
02-03669
RP Follow Up Items From CNRB Meeting
October 6, 2002
02-03835
Helmet Leak While Diving in Lower IFTS Pool
October 15, 2002
02-03826
Radiation Dose Reduction Efforts Failing
October 15, 2002
02-03899
Orange Tools Found Outside of Posted Area
October 17, 2002
02-04135
Missing Access Control Records In HIS-20
November 4, 2002
02-04140
RWCU Leak Degrading Containment
Atmosphere
November 4, 2002
02-04250
ALARA Assessment Of The Work In The
RWCU Heat Exchanger Room
November 11, 2002
02-04336
Inadequate Use Of All Available ALARA Tools
November 14, 2002
02-04429
Radiation Area Discovered Locked In Radwaste
November 21, 2002
02-04479
Escorted Radiation Workers Not Issued TLD
November 25, 2002
02-04497
PACP Gamma 60 Alarm
November 25, 2002
02-04574
Contamination Found On Chair in Radwaste
Control Room
December 4, 2002
02-04567
Operator Had A Dose Rate Alarm When
Entering RRA
December 4, 2002
02-03847
Potential Noncompliance With PAP-0114,
Storage of Radioactive Material In The Fuel
Pool
October 15, 2002
47
02-02134
Increased Dose Rates Around Septa Tube Box
Area On T647
June 28, 2002
02-02479
Cobalt-60 Activity Detected In WARF Air
Sample
July 29, 2002
02-00697
LHRA Door Lock Latching Mechanism Failed
March 10, 2002
02-00811
Engineering Controls Not Adequate During
Grinding 1G33 Drain Lines
March 18, 2002
02-01007
HIS-20 Database Indicates No TLDs Issued For
Individual When They Were
April 3, 2002
02-01201
Radioactive Material Found In Excess Of
Posting Limits
April 22, 2002
02-01267
Increase In Discrete particles Detected During
January 2002
April 26, 2002
02-01462
High Radiation Series Barricade List Is Incorrect
May 14, 2002
02-01689
Maintenance Use Of Improper RWP For HCU
Work
May 30, 2002
02-01792
Particle Discovered On Visitor Exiting The RRA
June 7, 2002
02-01896
LHRA Door Opened When Challenged
June 14, 2002
02-02244
RP Individual Signed Onto Wrong RWP
July 9, 2002
02-02697
Rad Workers Not Notifying RP Dosimetry When
Working At Another Site
August 12, 2002
02-03213
Increased Contamination Levels On Refueling
Floor
September 11, 2002
02-00177
Operator Entered RRA With His Personal
Dosimeter Not Activated
January 18, 2002
02-00786
Personnel Entry Into HRA Without Radiological
Brief
March 18, 2002
2OS3 Radiological Instrumentation
PNPP 9854
Gamma 60 Calibration Record
November 15, 2002
PNPP 9854
Gamma 60 Calibration Record
November 15, 2002
PNPP 8031
PCM-1B Calibration Record
April 22, 2002
PNPP 8031
PCM-1B Calibration Record
June 18, 2002
PNPP 10104
ABACOS 2000 Whole Body Counter Calibration
Record
August 9, 2002
48
Nuclide Libraries For The ABACOS 2000
System
October 30, 2002
Nuclide Libraries For The ABACOS 2000
System
October 17, 2002
PNPP 6885
Portable Ion Chamber Instrument Calibration
Record
October 14, 2002
PNPP 7268
Teletector 6112B Calibration Record
October 26, 2002
PNPP 10141
AMP-100 Calibration Record
October 18, 2002
4OA1 Performance Indicator Verification
Regulatory Assessment Performance Indicator
Rev. 2
Logs
Plant Narrative Logs
April 1-September
30 2002
Logs
Monthly Safety System Unavailability Logs
April 1-September
30 2002
CR 02-02728
Alert Range Data Obtained During RHR A SVI
E12T2001 Test
August 13, 2002
SVI-E12-T2001
RHR A Pump and Valve Operability Test
Rev. 11
4OA2 Identification and Resolution of Problems
CR 02-00284
Review of NRC Information Notice 2002-06 and
12/28/01 Pilgrim RPV Event
January 29, 2002
ARI-H13-P601-22
CRD Pump Auto Trip
Rev. 3
CR 02-00229
NRC notice #2002-05, FME in SLC Tanks
January 23, 2002
CHI-0004
System Chemical Treatment
Rev. 2
CR 02-02409
NRC Info Notice 2002-22 Degraded Bearing
Surfaces In GM/EMD Diesel Generators
July 22, 2002
CR 01-3483
OE SER 5-01 4-KV Breaker Failure, Switchgear
Fire, Main Turbine Generator Damage
September 28, 2001
Operating Experience Log
CR 02-01253-01
OE NRC IEN 2002-014 Ensuring Capability to
Evacuate From Owner Controlled Area
April 25, 2002
Emergency Preparedness and Site Evacuation
Information
NOP-WM-4001
Rev. 0
49
Material Accountability Control Log - Health
Physics Desk
December 16, 2002
Material Accountability Control Log - Lower
Containment Hatch
December 16, 2002
Material Accountability Control Log - Upper
Containment Hatch
December 16, 2002
Badge Access Transaction Report for Lower
Containment Hatch for period December 9
through December 10, 2002
Report Run
December 16, 2002
CR 01-3802
FME Program Self Assessment - Area For
Improvement
October 31, 2001
CR 01-3804
FME Program Self Assessment - Area For
Concern
October 31, 2001
CR 01-3808
FME Program Self Assessment - Area For
Concern
October 31, 2001
CR 01-3810
FME Program Self Assessment - Area For
Improvement
October 31, 2001
CR 02-2057
FME Performance Indicator
June 26, 2002
CR 02-2066
June 26, 2002
CR 02-2067
June 26, 2002
CR 02-2068
INPO 2002 SOER 95-01 Rec. #2
June 26, 2002
50
LIST OF INFORMATION REQUESTED
The following information is needed to be available onsite November 4, 2002, to support the
biennial Heat Sink Performance inspection, Procedure 711111.07. Please provide for the
following heat exchangers (HXs) Division 1 (Loop A) Emergency Closed Cooling Water (P-42)
System Heat Exchanger, and Division 2 (Loop B) Residual Heat Removal Heat Exchanger):
1.
Copy of the two most recently completed tests confirming thermal performance of each
HX. Include documentation and procedures that identify the types, accuracy, and
location of any special instrumentation used for these tests. (E.g., high accuracy
ultrasonic flow instruments or temperature instruments). Include calibration records for
the instruments used during these tests. Include drawings showing the piping
configurations and flowpaths for normal operation and testing for the HXs. Also indicate
where the instruments used for the tests were located. Describe the measures to
ensure proper fluid mixing for temperature considerations.
2.
Copy of the evaluations of data for the two most recent completed tests confirming the
thermal performance of each HX.
3.
Copy of the calculation which establishes the limiting (maximum) design basis heat load
which is required to be removed by each of these HXs.
4.
Copy of the calculation which correlates surveillance testing results from these HXs with
design basis heat removal capability (e.g., basis for surveillance test acceptance
criteria).
5.
The clean and inspection maintenance schedule for each HX. For the last two clean and
inspection activities completed on each HX, provide a copy of the document describing
the inspection results. Provide HX performance trending data tracked for each HX.
6.
Provide a copy of the document which identified the current number of tubes in service
for each heat exchanger and the supporting calculation which establishes the maximum
number of tubes which can be plugged in each HX. Provide a copy of the document
establishing the repair criteria (plugging limit) for degraded tubes which are identified in
each HX.
7.
Copy of the as-built HX specification sheets. Also provide the design specification and
heat exchanger data sheets for each HX. Copy of the vendor and component drawings
for each HX. Copy of the vendor and operating manuals for each HX.
8.
Provide a list of issues with a short description documented in your corrective action
system associated with these HXs in the past 3 years. Provide a list of issues with a
short description documented in your corrective action system associated with the
ultimate heat sink, especially any loss of heat sink events and any events or conditions
that could cause a loss of ultimate heat sink.
If the information requested above will not be available, please contact Gerard ODwyer as soon
as possible at (630) 829-9624 or E-mail - gfo@NRC.gov.