ML030290757
| ML030290757 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 01/29/2003 |
| From: | Kenneth Riemer NRC/RGN-III/DRP/RPB5 |
| To: | Nazar M Nuclear Management Co |
| References | |
| IR-02-009 | |
| Download: ML030290757 (81) | |
See also: IR 05000282/2002009
Text
January 29, 2003
Mr. M. Nazar
Site Vice President
Prairie Island Nuclear Generating Plant
Nuclear Management Company, LLC
1717 Wakonade Drive East
Welch, MN 55089
SUBJECT:
PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2
NRC INTEGRATED INSPECTION REPORT 50-282/02-09; 50-306/02-09
Dear Mr. Nazar:
On December 28, 2002, the U. S. Nuclear Regulatory Commission (NRC) completed an
integrated inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The
enclosed report documents the inspection findings which were discussed on January 13, 2003,
with you and other members of your staff.
This 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.
Based on the results of this inspection, the inspectors identified four issues of very low safety
significance (Green). These were determined to involve violations of NRC requirements.
However, because of the very low safety significance of the issues and because they were
entered into your corrective action program, the NRC is treating the issues as Non-Cited
Violations 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 Prairie Island Nuclear Generating 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 power reactors to strengthen licensee capabilities, improve 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
M. Nazar
-2-
Order. Phase 1 of TI 2515/148 was completed at all commercial nuclear power plants during
2002, and the remaining inspections are scheduled for completion in 2003. Additionally, table-
top security drills were conducted at several licensees to evaluate the impact of expanded
adversary characteristics and ICMs on licensee protection and mitigative strategies.
Information gained and discrepancies identified during the audits and drills were reviewed and
dispositioned by the Office of Nuclear Safety and Incident Response. For 2003, the NRC will
continue to monitor overall safeguards and security controls, conduct inspections, and perform
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 power reactors.
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/
Kenneth Riemer, Chief
Branch 5
Division of Reactor Projects
Docket Nos. 50-282; 50-306
Enclosure:
Inspection Report 50-282/02-09; 50-306/02-09
w/Attachment: Memorandum Regarding TI 2515/149
cc w/encl:
Plant Manager, Prairie Island
R. Anderson, Executive Vice President
and Chief Nuclear Officer
Site Licensing Manager
Nuclear Asset Manager
Commissioner, Minnesota
Department of Health
State Liaison Officer, State of Wisconsin
Tribal Council, Prairie Island Indian Community
J. Silberg, Esquire
Shawn, Pittman, Potts, and Trowbridge
P. Marker, Office of the Attorney General
Administrator, Goodhue County Courthouse
Commissioner, Minnesota Department
of Commerce
DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML030290757.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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NAME
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KRiemer
DATE
01/29/03
01/29/03
OFFICIAL RECORD COPY
M. Nazar
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ADAMS Distribution:
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C. Ariano (hard copy)
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
50-282; 50-306
License Nos:
Report No:
50-282/02-09; 50-306/02-09
Licensee:
Nuclear Management Company, LLC
Facility:
Prairie Island Nuclear Generating Plant, Units 1 and 2
Location:
1717 Wakonade Drive East
Welch, MN 55089
Dates:
October 1 through December 28, 2002
Inspectors:
J. Adams, Senior Resident Inspector
S. Ray, Senior Resident Inspector, Braidwood
S. Burgess, Senior Reactor Analyst
D. Karjala, Resident Inspector
D. Kimble, Resident Inspector, Monticello
M. Mitchell, Radiation Specialist
M. Holmberg, Reactor Inspector
K. Poertner, Mechanical Engineer, NRR
S. Sanders, Reactor Operations Engineer, NRR
R. Jickling, Emergency Preparedness Analyst
Approved by:
Kenneth Riemer, Chief
Branch 5
Division of Reactor Projects
2
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
1.
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
1R01
Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
1R04
Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
1R05
Fire Protection Area Walkdowns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R06
Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R07
Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
1R08
Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
1R11
Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R12
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R13
Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . 20
1R14
Personnel Performance Related to Non-Routine Plant Evolutions and Events
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
1R15
Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
1R16
Operator Workarounds (OWAs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
1R17
Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
1R19
Post-Maintenance Testing
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
1R20
Refueling and Other Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
1R22
Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
1R23
Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
1EP6
Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
2.
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
2OS1 Access Control to Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 27
2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls . . . . . 28
3.
SAFEGUARDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
3PP3
Response to Contingency Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
4.
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
4OA6 Meeting(s) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4OA7 Licensee-Identified Violations
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
LIST OF DOCUMENTS REVIEWED
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70
3
SUMMARY OF FINDINGS
IR 05000282/2002-009, 05000306/2002-009; Nuclear Management Company, LLC; on
10/1 -12/28/02, Prairie Island Nuclear Generating Plant, Units 1 & 2. Flood Protection
Measures, Inservice Inspection Activities, and Event Followup. In addition, generic safety
issue inspections in accordance with Temporary Instruction (TI) 2515/149, Mitigating Systems
Performance Index Pilot Verification, were conducted.
This report covers a 3-month period of baseline inspection. The inspection was conducted by
the resident inspectors, inspectors from the Region III office, and inspectors from the Office of
Nuclear Reactor Regulation. Four green findings were identified. The significance of most
findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter
(IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not
apply may be Green or be assigned a severity level after NRC management review. The
NRCs program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
A.
Inspection Findings
Cornerstone: Initiating Events
Green. A finding of very low safety significance was identified for the existence of
prohibited loose materials in the safety-related cooling water pump rooms on three
separate occasions. The materials were specifically prohibited due to the potential for
the loose materials to obstruct required critical drainage paths from these areas
adversely affecting measures for internal flood protection.
This finding is more than minor because it was associated with two of the cornerstone
attributes, affected the initiating events cornerstone objective, and was repetitive.
However, it was of very low safety significance because it did not contribute to the
likelihood of a primary or secondary system loss of coolant accident, did not contribute
to both the likelihood of a reactor trip and the likelihood that mitigation equipment or
functions would not be available, and did not increase the likelihood of a fire or
internal/external flood. The finding was determined to be a Non-Cited Violation (NCV) of
10 CFR 50, Appendix B, Criterion V. (Section 1R06)
Cornerstone: Barrier Integrity
Green. The inspectors identified a finding of very low safety significance regarding
inadequate instructions in three procedures used to conduct ultrasonic examination of
plant components. Specifically, the licensee had not included the mode of ultrasonic
wave propagation for the material under examination in these procedures.
The finding was more than minor because, if left uncorrected, it could have adversely
affected the licensees ability to perform an adequate inspection of safety-related
components, including the reactor vessel. However, it was of very low safety
significance because the licensee confirmed that appropriate ultrasonic examinations
had been conducted during past examinations. This finding was determined to be an
NCV of 10 CFR 50.55a(g)(4). (Section 1R08)
4
Green. The inspectors identified a finding of very low safety significance regarding
failure to conduct a periodic technical review of an ultrasonic examination procedure
used to detect cracks in steam generator and main steam nozzle inner radii.
The finding was more than minor because, if left uncorrected, it could have resulted in
failure to incorporate the appropriate technical requirements into the procedure and
consequently led to an ineffective examination of plant components. The finding was of
very low safety significance because the appropriate technical review was completed
and only one technical error was identified which impacted the technical adequacy of the
procedure. This finding was determined to be an NCV of 10 CFR Part 50, Appendix B,
Criterion V. (Section 1R08)
Cornerstone: Emergency Preparedness
Green. On November 3, 2002, the licensee failed to classify and declare an Unusual
Event in accordance with emergency plan implementing procedures following receipt of
a seismic event annunciator in the control room and after confirmation with an offsite
agency of the occurrence of an earthquake in Alaska.
The failure to declare an Unusual Event is associated with a risk significant
planning standard and determined to be of very low safety significance using Manual
Chapter 0609, Appendix B, Emergency Preparedness Significance Determination
Process, Sheet 2. The finding was determined to be an NCV of 10 CFR 50.54(q),
50.47(b)(4), and Sections IV.B and IV.D.3 of Appendix E of 10 CFR Part 50.
(Section 4OA3)
B.
Licensee-Identified Violations
Two violations of very low safety significance, which were identified by the licensee,
have been reviewed by the inspectors. Corrective actions taken or planned by the
licensee have been entered into the licensees corrective action program. The violations
and corrective action tracking numbers are listed in Section 4OA7.
5
REPORT DETAILS
Summary of Plant Status
Unit 1 was operated at or near full power until the unit was shut down for a refueling outage on
November 15, 2002. Unit 1 was made critical for physics testing on December 5, and the unit
was placed online on December 6. Unit 1 reached full power on December 9, and operated at
or near full power for the remainder of the inspection period.
Unit 2 was operated at or near full power for the entire inspection period.
1.
REACTOR SAFETY
Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01
Adverse Weather Protection (71111.01)
a.
Inspection Scope
During the week of November 3, 2002, the inspectors conducted plant walkdowns and
document reviews to verify that the risk significant systems were adequately protected
against impending cold weather. The inspectors concentrated on the safety-related
cooling water (CL) pumps, safeguards traveling screens, nonsafety-related CL pumps,
and external circulating water deicing equipment. The inspectors used the licensee
checklists and procedures listed at the end of this inspection report to verify that the
systems were lined up as required. In addition, the inspectors reviewed the Corrective
Action Program (CAP) Action Requests (ARs) and work orders (WOs) listed at the end
of this report to verify that the licensee had entered problems identified with cold
weather operations into the corrective action system and was taking the appropriate
compensatory actions.
b.
Findings
No findings of significance were identified.
1R04
Equipment Alignment (71111.04)
.1
Partial System Walkdowns
a.
Inspection Scope
The inspectors performed partial walkdowns of accessible portions of the following
trains of risk-significant mitigating systems while the trains were of increased importance
due to the redundant trains or other related equipment being unavailable:
12 safety-related diesel-driven cooling water (DDCL) pump during the
unavailability of the 22 safety-related DDCL pump on October 22, 2002; and
6
21 component cooling water (CC) heat exchanger while the 22 CC heat
exchanger was out-of-service for temperature control valve calibration on
December 12.
The inspectors utilized the valve and electric breaker checklists listed at the end of this
report to verify that the components were properly positioned and that support systems
were lined up as needed. The inspectors also examined the material condition of the
components and observed operating parameters of equipment to verify that there were
no obvious deficiencies. The inspectors reviewed outstanding WOs and CAP ARs
associated with the trains to verify that those documents did not reveal issues that could
affect train function. The inspectors referred to the Technical Specifications (TSs) and
Updated Safety Analysis Report (USAR) to determine the functional requirements of the
systems. In addition, the inspectors reviewed the CAP ARs listed at the end of this
report to verify that the licensee was identifying issues at an appropriate threshold and
entering them into their corrective action program.
b.
Findings
No findings of significance were identified.
.2
Complete System Walkdowns
a.
Inspection Scope
On November 1, 2002, the inspectors reviewed the alignment of the Unit 1 safety
injection (SI) system outside of containment. On November 25, the inspectors reviewed
the portion of the system inside containment. This system was selected because it was
considered both safety-significant and risk-significant in the licensees probabilistic risk
assessment. The inspection consisted of the following activities:
a review of plant procedures (including selected abnormal and emergency
procedures), drawings, and the USAR to identify proper system alignment;
a review of outstanding or completed temporary and permanent modifications to
the system;
a review of control room operator log entries from February 1 through
November 1, to identify potential system issues; and
an electrical and mechanical walkdown of the system to verify proper alignment,
component accessibility, availability, and current condition.
The inspectors also reviewed selected issues documented in CAP ARs, to determine if
they had been properly addressed. Documents reviewed during this inspection are
listed at the end of this report.
b.
Findings
No findings of significance were identified.
7
1R05
Fire Protection Area Walkdowns (71111.05)
a.
Inspection Scope
The inspectors conducted fire protection walkdown of fire area 86, intake screenhouse
on October 9, 2002. During the walkdown, the inspectors focused on the availability and
accessibility of fire protection equipment, the condition of fire fighting equipment, the
control of transient combustibles, and the condition and operating status of installed fire
barriers as described in fire hazards analysis and pre-fire plans. The inspectors
selected fire areas for inspection based on their overall contribution to internal fire risk,
as documented in the Individual Plant Examination of External Events (IPEEE).
Additionally, the inspectors assessed the inspected area for the potential to impact
equipment which could initiate a plant transient or that could impact the plants ability to
respond to a security event.
The inspectors reviewed the as-found condition of fire doors, dampers, penetration
seals, fire detectors, sprinklers, fire hoses and extinguishers, comparing the as-found
conditions to the configuration described in fire hazards analysis and pre-fire plans.
During this review, the inspectors verified equipment was in its appropriate location, was
available for immediate use, and was not obstructed. The inspectors also verified that
the as-found transient combustible loading was within the analyzed limits. The
inspectors reviewed applicable CAP ARs listed at the end of this report to verify that the
licensee was identifying fire protection issues at an appropriate threshold and entering
them into their corrective action program.
b.
Findings
No findings of significance were identified.
1R06
Flood Protection Measures (71111.06)
a.
Inspection Scope
On October 16, 2002, the inspectors reviewed and assessed protection measures for
internal flooding events. The inspectors evaluated whether the licensee took
appropriate precautions to mitigate the risk from internal flooding events. Specifically,
the inspectors performed the following:
reviewed the USAR and other selected design basis documents to identify those
areas susceptible to internal flooding;
reviewed the licensee's probabilistic risk analysis and associated flood protection
reports to identify risk significant flood areas and protective features;
reviewed abnormal and alarm response procedures associated with the
diagnosis and mitigation of flooding events;
performed a walkdown of the Units 1 and 2 safety-related DDCL pump rooms,
the common safety-related motor-driven cooling water (MDCL) pump room, and
the safeguards traveling screens room to evaluate whether appropriate flood
protection controls were being maintained; and
8
interviewed selected operating, engineering, and maintenance staff regarding
internal flood protection controls.
In addition, the inspectors reviewed the corrective action program to verify that identified
problems were being entered with the appropriate characterization and significance.
The inspectors also reviewed the corrective actions for flood protection related issues
documented in selected action requests.
b.
Findings
Introduction
On three separate occasions during the inspection period, inspectors identified the
existence of loose materials in the safety-related CL pump rooms. These materials
were specifically prohibited due to their potential adverse affect on required critical
drainage paths. The existence of these conditions resulted in a finding of very low
safety significance (Green) and a Non-Cited Violation (NCV) of NRC requirements.
Discussion
No deficiencies with the required flood protection measures were identified on
October 16. Subsequently, however, during routine plant walkdowns, the inspectors
identified the existence of loose materials in the safety-related cooling water pump
rooms that were specifically prohibited due to their potential adverse effect on required
critical drainage paths: on October 28, the inspectors identified two oil absorbent pads
in the 22 DDCL pump room; on November 6, the inspectors identified a temporary
power cable routed through a critical drainage path in the 12 DDCL pump room; and on
November 13, the inspectors identified a significant quantity of foreign material in the
121 MDCL pump room while the pump was aligned as a safety-related pump.
In each case listed above, the licensee failed to remove, properly control, or prevent
the introduction of materials that could block critical drainage paths associated with
operable safety-related CL pumps. Administrative Work Instruction 5AWI 8.9.0,
Section 6.2.2, states materials that could plug drainage paths be prevented from doing
so by tethering or anchoring the material when required equipment within the area is
operable. The materials identified by inspectors on October 28 and on November 13
were not tethered or anchored and in both cases the associated safety-related CL
pumps were considered operable.
In the November 6th case, Section 6.2.5 of 5AWI 8.9.0 states ensure temporary or
permanent changes that could impact drainage flow within any critical drainage area are
in accordance with the plants internal flooding analysis. The installation of the
temporary power cable identified by the inspectors had not been evaluated with respect
to the internal flooding analysis prior to its routing through the critical drainage area.
Analysis
The inspectors determined that this finding was more than minor. Inspection Manual
Chapter (IMC) 0612, Appendix E, Section 4, provides a number of examples of minor
9
procedural errors. Example a is similar to this case and indicates that a problem of
this type is more than minor if repetitive. The inspectors identified this issue on three
separate occasions within a 3-week period. The internal flood protection measures
required in these areas were not new requirements; the problems were in areas
routinely visited by operators; and the licensee missed opportunities to identify and
correct the issues in each of the cases prior to identification by inspectors. Additionally,
this finding was associated with two of the cornerstone attributes listed in IMC 0612,
Appendix BProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0612,</br></br>Appendix B" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., Section C and affected the initiating events cornerstone objective. For
example, the initiating events cornerstone objective to limit the likelihood of those events
that upset plant stability and challenge critical safety functions during shutdown as well
as power operations was affected by the materials that were introduced into the safety-
related CL pump rooms. Specifically, the design control and human performance
attributes were affected because the introduced materials changed the physical
conditions assumed in the internal flooding analysis. Therefore, for the time that these
conditions existed it could not be shown that the safety-related CL pumps would have
remained available during an internal flood. The loss of a safety-related cooling water
pump or pumps during an internal flood could upset plant stability.
The inspectors determined that the finding could be evaluated in accordance with
IMC 0609, Significance Determination Process [SDP], because the finding was
associated with an increase in the likelihood of an initiating event. Using the Phase 1
screening, the inspectors determined that the finding did not contribute to the likelihood
of a primary or secondary system loss of coolant accident, did not contribute to both the
likelihood of a reactor trip and the likelihood that mitigation equipment or functions would
not be available, and did not increase the likelihood of a fire or internal/external flood.
The inspectors determined the finding to be of very low safety significance (Green).
Enforcement
In part, 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
states that activities affecting quality shall be accomplished in accordance with
instructions, procedures, or drawings. Contrary to the above, the licensee failed to
implement the requirements specified in procedure 5AWI 8.9.0, Section 6. Since the
licensee entered the conditions identified by the inspectors into their corrective action
program with AR CAP 026010, AR CAP 026158, and AR CAP 026291, this violation is
being treated as an NCV in accordance with VI.A.1 of the NRCs Enforcement Policy
(NCV 50-282/306/02-09-01).
1R07
Heat Sink Performance
a.
Inspection Scope
On November 15, 2002, the inspectors conducted a walkdown of the data acquisition
test equipment installed on the Unit 1 CC heat exchangers and observed the real-time
data obtained during pre-test equipment functional tests.
The inspectors reviewed the Unit 1 CC heat exchanger test data obtained from the
performance tests conducted on November 16. The inspectors compared the test
results to the heat exchangers required performance specified in the CC design basis
10
documents listed at the end of this report. The inspectors evaluated test data for
indications of heat exchanger deficiencies that could mask degraded performance and
other heat exchanger problems that would be indicative of potential common cause heat
sink problems that potentially could increase plant risk.
The inspectors reviewed the licensees performance with respect to the identification
and resolution of problems associated with heat sink performance problems. The
inspectors focused their evaluation on problems that could result in an initiating event or
affect multiple heat exchangers in mitigating systems, thereby increasing risk. A list of
corrective action documents reviewed by the inspectors has been included at the end of
this report.
b.
Findings
No findings of significance were identified.
1R08
Inservice Inspection Activities (71111.08)
a.
Inspection Scope
The inspectors evaluated the implementation of the licensees inservice inspection
program for monitoring degradation of the reactor coolant system (RCS) boundary and
risk significant piping system boundaries, based on review of records and in-process
observation of nondestructive examinations.
From November 18 through November 26, 2002, the inspectors observed:
ultrasonic (UT) examination of an elbow-to-pipe weld W-3 and safe-end-to-elbow
weld W-2 on the pressurizer safety relief line inside the Unit 1 containment;
UT examination of a reducer-to-safe-end weld W-13 on the pressurizer spray
line inside the Unit 1 containment;
dye penetrant (PT) examination of pipe-to-elbow weld W-25 on the residual heat
removal (RHR) pump loop B line inside the Unit 1 containment;
PT examination of the pipe-to-elbow weld W-6 on RCS loop A inside the Unit 1
containment;
PT examination of the nozzle-to-pipe weld W-12 on RCS crossover loop A inside
the Unit 1 containment;
acquisition and evaluation of eddy current (ET) data on the Unit 1 steam
generators (SGs), which occurred in a service building outside the protected
area;
video taped visual examination of the secondary side inspection of SG 11 at the
top of the tubesheet to locate potential loose parts, which occurred in a service
building within the protected area; and
in situ pressurization of two SG tubes inside the Unit 1 containment. The tubes
tested were located in SG 11 at row 14, column 31, and row 11, column 37, and
each contained a single axial ET indication located just above the top of the
tubesheet.
From November 18 through November 26, 2002, the inspectors reviewed:
11
repair and replacement records required by the American Society of Mechanical
Engineers (ASME) Code for the performance of a preventative weld buildup on
the control rod drive intermediate canopy seal weld and the replacement of the
B loop pressurizer spray valve CV 31225; and
nondestructive examination reports with Code recordable indications identified
during previous UT and PT examinations.
The records reviewed and activities observed were evaluated for conformance with
requirements in Section III, V, IX, and XI of the ASME Code.
The inspectors also reviewed a sample of inservice inspection related problems
documented in the licensees corrective action program, to assess conformance with
10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements.
b.
Findings
(1)
Missed SG 12 and SG 21 Tubesheet-to-Head Weld UT Examinations
Introduction
On November 25, 2002, the inspectors identified an unresolved item (URI) associated
with the licensees failure to perform a volumetric examination of the Unit 1 SG 12 and
Unit 2 SG 21 tubesheet-to-head W-A welds during the 1999 and 2002 refueling
outages, respectively. At the conclusion of this inspection, the inspectors could not
determine the risk of this finding because the licensee had not yet completed re-
examination of these welds to determine the size and significance of weld flaws left in
service.
Description
For Unit 1, the licensee identified a flaw during the 1999 UT examination of the SG 11
tubesheet-to-head weld W-A that exceeded Code acceptance standards of Table
IWB-3410-1. The licensee accepted the flaw based on an analysis derived in
Westinghouse document WCAP 14166, Handbook on Flaw Evaluation for Prairie
Island Units 1 and 2 Steam Generators and Pressurizer. However, the licensee did not
examine the SG 12 W-A weld during this outage as required by paragraph IWB-2430 of
Section XI of the 1989 Edition, no Addenda, of the ASME Code. For the SG 12 W-A
weld, the licensee had not completed a UT examination since 1998. The licensee
entered the failure to perform the SG 12 W-A weld examination into the corrective action
system (CAP 026715) and no immediate operability evaluation was required because
Unit 1 was in cold shutdown. The licensee subsequently initiated actions to perform
examinations of the Unit 1 SG 11 and SG 12 W-A welds during the current refueling
outage.
During the extent of condition review, the licensee identified that a similar condition also
existed for the Unit 2 SG W-A welds. When the licensee examined the SG 22 weld W-A
in February of 2002, 14 flaws were identified which exceeded Code acceptance
standards of Table IWB-3410-1. The licensee applied a weld flaw analysis derived in
12
WCAP 14166 to accept these flaws for continued service. However, the licensee did
not expand the scope of the inspection to include UT examination of the SG 21 weld
W-A. The licensee last performed a UT examination of one-third of the SG 21 weld
W-A in May of 2000. The licensee entered the failure to perform the SG 12 W-A weld
examination into the corrective action system (CAP 026755), considered that the SG 21
weld W-A was operable, and was evaluating the need to seek NRC approval for Code
relief to allow deferral of this weld examination until the next refueling outage in the fall
of 2003. In operability recommendation (OPR) 000360, the licensee concluded that the
SG 21 W-A weld was operable because only Code acceptable indications were
identified during the previous two UT examinations conducted in 1997 and 2000, which
provided assurance that no structurally significant flaws could exist. The inspectors
noted that the licensee had last performed a full inspection of this weld in 1993 and had
not established a basis for their conclusion that no structurally significant flaws were
present. The licensee subsequently revised OPR 000360 and included a technical
evaluation of the potential inservice flaw sizes based on a methodology established in
WCAP 14166. The licensees revised OPR considered embedded flaw growth using a
series of loading transients with the maximum applied stress intensity factor for the
maximum size flaw detected. Based on this methodology, the licensee concluded that
the indications identified during the 2000 refueling outage were acceptable for 10 years
of service without further inspection and SG 21 was operable. The inspectors noted that
the application of WCAP 14166 to inservice flaws in SG W-A welds had been accepted
by the NRC for previous flaw evaluations, however, not as a basis to allow deferring the
required Code examinations.
The licensee was in the third Code interval and was committed to the requirements of
Section XI, 1989 Edition, no Addenda, of the ASME Code for these inservice
examinations. Specifically, the SG head-to-tubesheet W-A welds were required to be
volumetrically examined once per Code interval (10 years) in accordance with the Table
IWB-2500 Category B.2.40. Section XI, IWB-2430 required Examinations performed in
accordance with Table IWB-2500-1 that reveal indications exceeding the acceptance
standards of Table IWB-3410-1 shall be extended to include additional examinations at
this outage. The additional examinations shall include the remaining welds, areas, or
parts included in the inspection item listing... This statement required the licensee to
take prompt (at this outage) actions to determine the extent of potential degradation
when inservice weld flaws were identified which exceed Code limits. Therefore, the
inspectors were concerned that the licensees decision to not examine SG 12 and
SG 21 W-A welds during the 1999 and 2002 refueling outages could have potentially
allowed weld flaws of unacceptable size to remain in service.
The licensee staff discussed their decision to not apply the Section XI, IWB-2430
requirements to expand the scope of weld examinations for these SG W-A welds. The
licensee staff had applied a successive examination schedule discussed in Section XI,
IWB-2420 to the SG 11 and SG 22 W-A welds because flaws were identified that
required an analysis to leave in service. The licensee staff then excluded application of
IWB-2430 requirements to expand the extent of weld examinations to SG 12 and SG 21
W-A welds, because SG 11 and SG 22 W-A welds were in a successive examination
schedule. The licensee staff had interpreted the Section XI, IWB-2430 statement
examinations performed in accordance with Table IWB-2500-1, to allow excluding
expansion of weld examinations for new weld flaws identified during successive
13
examinations performed under IWB-2420. Section XI, IWB-2420(b) required If flaw
indications or relevant conditions are evaluated in accordance with IWB-3132.4 or
IWB-3142.4, respectively, and the component qualifies as acceptable for continued
service, the areas containing such flaw indications or relevant conditions shall be
reexamined during the next three inspection periods listed in the schedules of inspection
programs of IWB 2410. For SG 11 and SG 22 the licensee was performing these
successive examinations beginning in 1994 for SG 11 and 1989 for SG 22 after
identification of subsurface flaws which exceeded acceptable sizes as identified in
Table IWB-3410-1. The licensee staff believed that these subsurface flaw indications
which exceeded Code acceptance criteria, were likely fabrication-related weld defects
(e.g., slag, inclusions or weld porosity), vice service-induced. However, the licensees
manual UT examination methods were not sufficient to confirm the flaw locations or to
determine changes in flaw size (e.g., flaws indications sometimes got smaller in
subsequent examinations). Therefore, the licensee staff had considered each flaw
identified in the SG W-A welds that exceeded Code acceptance criteria during these
examinations to be a new flaw.
The inspectors requested the licensee provide a technical basis to support their
application of Code requirements to not expand the scope of the SG W-A weld
examinations. At the conclusion of the inspection, the licensee staff did not have a
documented technical basis, nor an NRC-endorsed Code Case, which supported their
potentially nonconservative application of Code requirements.
Analysis
The licensee performance deficiency associated with this finding was a failure to follow
the ASME Code examination expansion requirements to volumetrically examine weld
W-A on SG 12 and SG 21 during the 1999 and 2002 refueling outages respectively.
The inspectors reviewed this issue against the guidance contained in Appendix B, Issue
Dispositioning Screening, of IMC 0612, Power Reactor Inspection Reports. In
particular, the inspectors compared this finding to the findings identified in Appendix E,
Examples of Minor Issues, of IMC 0612 to determine whether the finding was minor.
Following that review, the inspectors concluded that the guidance in Appendix E was not
applicable for the specific finding since no examples were provided which involved
failure to perform inservice examinations. As a result, the inspectors compared this
performance deficiency to the minor questions contained in Section C, Minor
Questions, to Appendix B of IMC 0612. The inspectors concluded that the issue was
more than minor because the finding, if left uncorrected, could become a more
significant safety concern. Specifically, the licensees failure to volumetrically examine
weld W-A in SG 12 and SG 21 could have resulted in plant operation with unacceptable
weld flaws that challenged the reactor coolant pressure boundary integrity.
As a result, the inspectors reviewed this issue in accordance with IMC 0609,
Significance Determination Process. The inspectors conducted this review utilizing the
SDP Phase 1 Screening Worksheet for IE [Initiating Events], MS [Mitigating Systems]
and B [Barrier Integrity] Cornerstones. The inspectors determined that this issue
potentially affected the NRCs Barrier Integrity Cornerstone. However, the inspectors
could not evaluate the significance of this issue until the licensee completed UT
14
examination of SG 12 weld W-A and SG 21 weld W-A to determined the size and
significance of weld flaws left in service.
Enforcement
Requirements of 10 CFR 50.55a(g)(4) are, in part, that throughout the service life of a
pressurized water-cooled nuclear power facility, components must meet the
requirements set forth in the ASME Code,Section XI. Section XI, IWB-2430 required
Examinations performed in accordance with Table IWB-2500-1 that reveal indications
exceeding the acceptance standards of Table IWB-3410-1 shall be extended to include
additional examinations at this outage. The additional examinations shall include the
remaining welds, areas, or parts included in the inspection item listing...
Contrary to these requirements, on May 22, 1999, the licensee performed an
examination as described in Table IWB-2500-1 (Code item B.2.40) for Unit 1 SG 11
weld W-A that revealed an indication which exceeded the acceptance standards of
Table IWB-3410-1 and failed to include additional examinations of the remaining Code
item B.2.40 welds of Table IWB-2500-1 during the 1999 outage. Specifically, the
licensee failed to perform a volumetric examination of weld W-A on SG 12 during the
1999 outage and this weld had not received a volumetric inspection since 1998.
Contrary to these requirements, on February 15, 2002, the licensee performed an
examination as described in Table IWB-2500-1 (Code item B.2.40) for Unit 2 SG-22
weld W-A that revealed 14 indications which exceeded the acceptance standards of
Table IWB-3410-1 and failed to include additional examinations of the remaining Code
Item B.2.40 welds of Table IWB-2500-1 during the 2002 Unit 2 refueling outage.
Specifically, the licensee failed to perform a volumetric examination of weld W-A on
SG 21 during the February 2002 outage and this weld had not received a volumetric
inspection since May 2000.
Because the significance of this finding is not yet known, it is considered an Unresolved
Item (URI 50-282/306/02-09-02) pending completion of a UT examination of weld W-A
on SG 12 and weld W-A on SG 21.
(2)
Lack of ASME Code Requirement in Ultrasonic Examination Procedures
Introduction
The inspectors identified a finding of very low significance (Green) and an associated
NCV of 10 CFR 50.55a(g)(4) related to inadequate instructions in three procedures used
to conduct ultrasonic examination of plant components.
Description
On November 20, 2002, the inspectors identified three procedures used for
conducting UT examinations of ASME Code components, that lacked a Code
requirement to specify the mode of wave propagation in the material. Specifically,
procedures ISI-UT-3, Ultrasonic Examination of Ferritic Vessels, Revision 10,
ISI-UT-3A, Ultrasonic Examination of Reactor Vessel Welds, Revision 8, and
15
ISI-UT-5E, Ultrasonic Examination of Steam Generator Primary and Main Steam
Nozzle Inner Radii, Revision 1, lacked instructions which described the mode of wave
propagation in the material under examination. The inspectors were concerned that
failure to include this Code requirement could result in the licensee staff selecting an
incorrect UT transducer, which could result in an ineffective weld examination. For
example, an L-wave transducer produces both a refracted shear wave and longitudinal
wave within the material examined. These two sound waves enter the material at
different angles and propagate at different speeds which could cause the licensee staff
to misinterpret flaw signals or misinterpret the extent of weld examination coverage
achieved.
Analysis
The licensee performance deficiency associated with this finding was failure to
incorporate an ASME Code requirement to specify the mode of wave propagation into
procedures ISI-UT-3, ISI-UT-3A and ISI-UT-5E. The inspectors reviewed this issue
against the guidance contained in Appendix B, Issue Dispositioning Screening, of
IMC 0612, Power Reactor Inspection Reports. In particular, the inspectors compared
this finding to the findings identified in Appendix E, Examples of Minor Issues, of
IMC 0612 to determine whether the finding was minor. The inspectors concluded that
the guidance in Appendix E was not applicable for the specific finding since no
examples were provided which involved procedure errors which could lead to ineffective
weld examinations affecting the pressure boundary integrity. As a result, the inspectors
compared this performance deficiency to the minor questions contained in Section C,
Minor Questions, to Appendix B of IMC 0612. The inspectors concluded that the issue
was more than minor because the finding, if left uncorrected, could become a more
significant safety concern, in that it could have adversely affected the licensees ability to
detect flaws in safety-related components, including the reactor vessel. The failure to
specify the mode of wave propagation could have allowed the licensee inspection staff
to select an L-wave transducer when a shear wave transducer was appropriate or vice
versa. The use of an incorrect transducer could render the weld examination ineffective,
in that unacceptable weld flaws could potentially go undetected. Based on review of
past examination records, the licensee determined that improper transducers had not
been used for previous UT examinations. The licensee subsequently initiated changes
to the procedures to include the mode of wave propagation in the material under
examination.
As a result, the inspectors reviewed this issue in accordance with IMC 0609
Significance Determination Process, utilizing the SDP Phase 1 Screening
Worksheet for IE, MS and B Cornerstones. The inspectors determined that none
of the above cornerstones were directly impacted by this finding. Therefore, the
inspectors concluded that this issue was not suited for SDP analysis, in accordance
with Section 0506.b(3) of IMC 0612. Because this issue had not resulted in an
ineffective weld examination, the inspectors concluded that it was of very low risk
significance (Green).
16
Enforcement
Requirements of 10 CFR 50.55a(g)(4) are, in part, that throughout the service life of a
pressurized water-cooled nuclear power facility, components must meet the
requirements set forth in ASME Code,Section XI. Section XI, Article I-2100 required
Ultrasonic examination of vessel welds greater than 2 inches thickness shall be
conducted in accordance with Article 4 of Section V... Section V, Article 4, T-423,
Written Procedure Requirements, required Each procedure shall include at least the
following information: ..(f) angles and mode(s) of wave propagation in the material.
Contrary to these requirements, on November 20, 2002, the inspectors identified
that procedures ISI-UT-3, Ultrasonic Examination of Ferritic Vessels, Revision 10,
ISI-UT-3A, Ultrasonic Examination of Reactor Vessel Welds, Revision 8, and
ISI-UT-5E, Ultrasonic Examination of Steam Generator Primary and Main Steam
Nozzle Inner Radii, Revision 1, did not specify the mode(s) of wave propagation in
the material. The failure to specify the mode(s) of wave propagation in the material in
these procedures were examples where the requirements of 10 CFR 50.55a(g)(4) were
not met and was a violation. However, because of the very low safety significance
and because the issue was entered into the licensees corrective action program
(CAP 026513), it is being treated as an NCV, consistent with Section VI.A.1 of the
Enforcement Policy (NCV 50-282/306/02-09-03).
(3)
Missed Technical Review for Ultrasonic Examination Procedure
Introduction
The inspectors identified a finding of very low significance (Green) and an associated
NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
related to a failure to conduct a periodic technical review for an ultrasonic examination
procedure used to detect cracks in SG and main steam nozzle inner radii.
Description
On November 20, 2002, the inspectors identified that the licensee had failed to perform
a periodic review for technical adequacy of procedure ISI-UT-5E used to perform
ultrasonic examination of SG and main steam nozzle inner radii. The licensee issued
this procedure in 1997, and as of November 20, 2002, had not performed a review to
confirm that it was up-to-date with current requirements and technically accurate.
Further, the inspectors had discovered a technical error associated with the mode of
wave propagation in this procedure as discussed in Section 1R08.b.(2) above, which
could have affected the effectiveness of the UT examination. During the extent of
condition review for this issue, the licensee staff identified 11 other non-destructive
examination procedures associated with the erosion-corrosion control program
(e.g., monitors pipe wall loss) that had not received this periodic review. The licensee
personnel had failed to enter these procedures into the Document Review Database,
which the licensee used to track implementation of the required procedure reviews.
17
Analysis
The licensee performance deficiency associated with this finding, was failure to perform
a periodic review for technical adequacy of procedure ISI-UT-5E. The inspectors
reviewed this issue against the guidance contained in Appendix B, Issue Dispositioning
Screening, of IMC 0612, Power Reactor Inspection Reports. In particular, the
inspectors compared this finding to the findings identified in Appendix E, Examples of
Minor Issues, of IMC 0612 to determine whether the finding was minor. The inspectors
concluded that the guidance in Appendix E was not applicable for the specific finding
since no examples were provided which involved failure to conduct technical reviews of
procedures which are used to confirm the integrity of the reactor coolant pressure
boundary. As a result, the inspectors compared this performance deficiency to the
minor questions contained in Section C, Minor Questions, to Appendix B of IMC 0612.
The inspectors concluded that the issue was more than minor because the finding, if left
uncorrected, could become a more significant safety concern. Specifically, the
inspectors were concerned that the failure to perform this review for procedure
ISI-UT-5E could result in failure to incorporate the appropriate technical requirements
and consequently lead to an ineffective examination of plant components. The licensee
subsequently completed the reviews for procedure ISI-UT-5E (and the 11 others
identified by the licensee) and did not identify any technical errors, other than the one
technical error associated with mode(s) of wave propagation as discussed in Section
1R08.b.(2). As a result, the inspectors reviewed this issue in accordance with IMC 0609
Significance Determination Process, utilizing the SDP Phase 1 Screening Worksheet
for IE, MS and B Cornerstones. The inspectors determined that none of the above
cornerstones were directly impacted by this finding; therefore, this issue was not suited
for SDP analysis in accordance with Section 0506.b(3) of IMC 0612. Because this issue
had not resulted in ineffective examinations of plant components, the inspectors
concluded that it was of very low risk significance (Green).
Enforcement
10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
required, in part, that Activities affecting quality shall be prescribed by documented
instructions, procedures, or drawings, of a type appropriate to the circumstances and
be accomplished in accordance with these instructions, procedures, or drawings.
Procedure MMRN 1.1, Reference Manual Policy and Administration, Revision 0
required that all procedures shall be reviewed and/or revised within a 36-month period.
Contrary to these requirements, the inspectors identified that as of November 20, 2002,
procedure ISI-UT-5E, Ultrasonic Examination of Steam Generator Primary and Main
Steam Nozzle Inner Radii Revision 1, had not received a review/revision within the
36-month period following the initial procedure issue date of October 6, 1997. The
failure to conduct a periodic review of this procedure for technical adequacy was an
example of where the requirements of 10 CFR 50, Appendix B, Criterion V, were not
met and was a violation. However, because of the very low safety significance and
because the issue was entered into the licensees corrective action program
(CAP 026514 and CAP 026574), it is being treated as an NCV, consistent with
Section VI.A.1 of the Enforcement Policy (NCV 50-282/306/02-09-04).
18
1R11
Licensed Operator Requalification (71111.11)
.1
Written Examination and Operating Test Results
a.
Inspection Scope
The inspectors reviewed the pass/fail results of individual written tests, operating tests,
and simulator operating tests (required to be given per 10 CFR 55.59(a)(2))
administered by the licensee during calendar year 2002.
b.
Findings
No findings of significance were identified.
1R12
Maintenance Effectiveness (71111.12)
.1
Multiple Cooling Water Pump Bearing/Seal Water Failures
a.
Inspection Scope
On October 19, 2002, the inspectors reviewed AR CAPs 023088, 024290, 024661,
024872, 025483, 025825, and 025866 that identified problems with safety-related
CL pump bearing/seal water. The proper operation of CL pump bearing/seal water
supports the operability of the safety-related CL pumps that provide several safety-
significant maintenance rule functions.
The inspectors performed an in-office review of corrective action program documents
associated with the bearing/seal water failures. The inspectors compared the licensees
maintenance documentation to the requirements contained in the administrative work
instruction (AWI) procedures for the performance of nuclear maintenance, investigation,
and troubleshooting. The documents reviewed are listed at the end of this report.
The inspectors reviewed the licensees implementation of the maintenance rule for the
repeat failures of the bearing/seal water by comparing their actions to the requirements
contained in the Maintenance Rule, 10 CFR 50.65, and Industry Guidelines for
Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, NUMARC 93-01.
The inspectors evaluated whether the safety-related CL pumps were scoped in
accordance with the maintenance rule, and whether the performance problems
associated with bearing/seal water constituted maintenance preventable functional
failures.
b.
Findings
No findings of significance were identified.
19
.2
Auxiliary Building Roof Leakage
a.
Inspection Scope
On October 25, 2002, the inspectors evaluated the licensees disposition of the
problems documented in General Condition Report (GEN) 200202455 and AR
CAP 024598. Both of these corrective action documents identified equipment failures
caused by auxiliary building roof leakage. During the review of these problems, the
inspectors evaluated the licensees use of appropriate work practices, review of
problems for common cause failures, Maintenance Rule scoping, Maintenance Rule
classification, Maintenance Rule performance criteria, and the trending of key
performance parameters. The inspectors compared the actions taken by the licensee in
response to these problems to established maintenance, Maintenance Rule
implementation procedures, and documents listed at the end of this report. In addition,
the inspectors reviewed the corrective action program documents listed at the end of
this report to verify that the licensee had entered problems identified with effectiveness
of maintenance and the implementation of the Maintenance Rule into their corrective
action program.
b.
Findings
No findings of significance were identified.
.3
Resolution of External Circulating Water Intake Screen Bypass Gate Repeat Failures
URI 50-282/306/02-08-02
a.
Inspection Scope
On August 20, 2002, during a previous inspection, while investigating the repeat failures
of the external circulating water intake screen bypass gates, the inspectors identified
that the licensee had inappropriately classified the bypass gates as low safety significant
components. Since the bypass gates were improperly classified, the licensees
performance criteria were also inappropriate and bypass gate failures were not properly
evaluated for maintenance preventable functional failures. The inspectors determined
that the inappropriate maintenance rule safety significance classification of the intake
bypass gates was a Green Finding. The inspectors concluded that a violation
determination could not be completed until appropriate performance criteria for the low
safety significant standby safety significance classification were first established by the
maintenance rule expert panel. The need to evaluate the finding for violations of NRC
requirements was left as an Unresolved Item (URI 50-282/306/02-08-02).
During the current inspection, on November 29, the inspectors reviewed the
licensees new performance criteria for the bypass gates, (a)(1) evaluation of gate
failures in the previous 2 years, and the Maintenance Rule Expert Panel minutes
from November 27. The inspectors compared the changes to the guidance provided in
NUMARC 93-01 and the requirements of the Maintenance Rule, 10 CFR 50.65.
20
b.
Findings
The inspectors determined that the performance of the bypass gates had not exceeded
(a)(2) performance criteria. URI 50-282/306/02-08-02 is closed. No findings were
identified.
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13)
a.
Inspection Scope
The inspectors reviewed the licensees management of plant risk during emergent
maintenance activities and during activities where more than one risk significant system
or train was unavailable. The activities were chosen based on their potential for
increasing the probability of an initiating event or impacting the operation of safety
significant mitigating equipment. The inspection was conducted to verify that evaluation,
planning, control, and performance of the work were done in a manner to reduce the
risk and minimize the duration where practical, and that contingency plans were in place
where appropriate. The inspectors reviewed daily configuration risk assessment
records, observed shift turnover meetings, observed daily plant status meetings, and
reviewed risk assessment documents listed at the end of this report to verify that the
equipment configurations were properly listed, that protected equipment was identified
and controlled, and that significant aspects of plant risk were communicated to the
necessary personnel. The inspectors discussed daily and emergent risk assessments
with risk assessment engineers and operators.
The inspectors reviewed the following emergent and planned maintenance activities
associated with the simultaneous unavailability of the listed maintenance rule risk
significant systems:
on October 16, 2002, the simultaneous unavailability of the 22 turbine-driven
auxiliary feedwater (AFW) pump, 124 air compressor, 121 intake bypass gate,
and 121 screenwash pump;
on October 21, the simultaneous unavailability of the 22 DDCL pump and the
D2 emergency diesel generator;
on October 28, the simultaneous unavailability of the 21 RHR pump and
123 instrument air compressor; and
on November 4, the simultaneous unavailability of the 121 instrument air
compressor, 121 screenwash pump, 121 bypass gate, D1 emergency diesel
generator, 11 RHR pump discharge to 11 SI pump suction motor-operated valve
MV 32206, and 11 AFW pump.
The inspectors reviewed several ARs to verify that problems associated with plant risk
assessment were identified at an appropriate threshold, and that corrective actions
commensurate with the significance of the issue were identified and implemented. A
detailed list of the documents reviewed during this inspection is included at the end of
the report.
21
b.
Findings
No findings of significance were identified.
1R14
Personnel Performance Related to Non-Routine Plant Evolutions and Events (71111.14)
.1
Licensee Response to a Seismic Alarm Received Following Alaskan Earthquake
a.
Inspection Scope
On November 3, 2002, a seismic alarm was received in the control room. Operators
entered Abnormal Operating Procedure AB-3, Earthquakes. The inspectors reviewed
the operators response to this unplanned event and compared their actions to the
actions specified in annunciator response procedures, abnormal operating procedures,
and the emergency plan implementing procedures.
b.
Findings
The licensee entered AB-3 on receipt of the alarm and confirmed the occurrence of an
earthquake in Alaska by contacting the National Earthquake Information Center in
Boulder, Colorado. The control room seismic monitor energized, the Seismic Event
annunciator was received, and magnetic tape recorder operation initiated. However, a
failure of the seismic monitor chart paper recorder to produce a visible indication on its
chart paper prevented the timely evaluation of the peak acceleration experienced during
the event. Additionally, the failure of operators to follow the emergency plan
implementing procedure for event classification prevented classification and declaration
of the event. This finding is discussed in detail in Section 4OA3 of this report.
.2
Planned Non-Routine Evolution Observed During the Unit 1 Refueling Outage
a.
Inspection Scope
The inspectors observed planned non-routine activities performed during the Unit 1
refueling outage. The inspectors reviewed operator performance and compared their
actions to the specified actions contained in plant operating, annunciator response, and
abnormal operating procedures. Among the significant activities the inspectors
observed during the refueling outage were the unit shutdown, cooldown, and entry into
RHR operations on November 16, 2002; RCS draindown activities and reactor vessel
head removal on November 20; RCS operation at reduced inventory conditions for
installation and removal of SG nozzle dams on November 18 and 27; RCS fill and
venting; RCS heat up to normal operating temperature and pressure; reactor startup;
and synchronization of the main generator to the grid from December 2 through
December 5. The inspectors reviewed CAP ARs to verify that minor issues identified
during the performance of these activities were identified and entered into the licensees
corrective action system for resolution.
b.
Findings
No findings of significance were identified.
22
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors evaluated plant conditions, selected action requests, and other
corrective action process documents associated with risk significant components and
systems for which operability was questioned. On October 8, 2002, the inspectors
evaluated the licensees assessment of operability for the Units 1 and 2 containment
buildings after the most recent loss-of-coolant accident analysis revealed a post-
accident containment temperature in excess of the temperature assumed in the
containment fan cooling unit heat removal analysis. This condition was evaluated to
determine whether the continued operability of the containment structure and the
systems located inside the containment structure were justified. The inspectors
compared the containment structure and systems design criteria in TSs and USAR to
the operability evaluation to verify that the containment structure and systems would
remain operable. The inspectors verified that compensatory measures identified in the
operability evaluation were in place, functioned as intended, and were properly
controlled. A detailed list of the documents reviewed during this inspection is included at
the end of the report.
b.
Findings
No findings of significance were identified.
1R16
Operator Workarounds (OWAs) (71111.16)
.1
Review of Selected Workarounds
a.
Inspection Scope
On November 1, 2002, the inspectors reviewed OWAs associated with venting of
SI pumps to mitigate possible gas intrusion. The venting activity required operators to
stand on the respective SI pump. The inspectors verified that the functional capability
of the system, human reliability in responding to an initiating event, or the ability of
operators to implement abnormal or emergency operating procedures were not
significantly affected. The inspectors reviewed the applicable sections of the USAR
and TSs and discussed the OWAs with control room operators. The inspectors also
reviewed operator logs to identify any potential conditions that should be considered
OWAs. A detailed list of the documents reviewed during this inspection is included at
the end of the report.
b.
Findings
No findings of significance were identified.
23
.2
Cumulative Effects of OWAs
a.
Inspection Scope
On December 12, 2002, the inspectors reviewed the cumulative effect of all identified
OWAs to determine if there was a significant impact on plant risk or on the operators
ability to respond to a transient or an accident. The inspectors used the documents
listed at the end of this report to evaluate the list of OWAs. The inspectors discussed
the list of current OWAs with the operations support manager.
b.
Findings
No findings of significance were identified.
1R17
Permanent Plant Modifications (71111.17)
a.
Inspection Scope
During the week ending November 16, 2002, the inspectors reviewed design change
modification 02CL01. This modification provided a new normal source of bearing and
shaft lubrication water from the well water system, while retaining the safety-related
supply from the CL system on the 22 DDCL pump. The inspectors reviewed and
compared the systems design basis, licensing basis, and performance capability to the
installed modification in order to verify that the system performance had not been
degraded by the installation of the modification. The inspectors also reviewed changes
that the modification installation did not place the plant in an unsafe configuration.
The inspectors considered the design adequacy of the modification by performing a
review of the modifications impact on the plants material requirements and
replacement components, response time, control signals, equipment protection,
operation, failure modes, and other related process requirements.
b.
Findings
No findings of significance were identified.
1R19
Post-Maintenance Testing (71111.19)
a.
Inspection Scope
The inspectors reviewed post-maintenance testing activities associated with
maintenance on important mitigating, barrier integrity, and support systems to ensure
that the testing was performed adequately, demonstrated that the maintenance was
successful, and that operability was restored. The inspectors reviewed the appropriate
sections of the TSs, USAR, and maintenance documents to determine the systems
safety functions and the scope of the maintenance. In addition, the inspectors reviewed
ARs to verify that minor deficiencies identified during these inspections were entered
into the licensees corrective action system. A detailed list of the documents reviewed
during this inspection is included at the end of the report.
24
The inspectors observed and evaluated the post-maintenance activities for the following:
124 air compressor following 1000-hour preventive maintenance (PM) on
October 17, 2002, WO 0206295;
22 DDCL pump following annual inspection and other maintenance activities on
October 24, WO 025889;
11 SI pump following corrective and preventive maintenance on November 6,
22 DDCL pump following PM on November 15, WO 0204494; and
22 DDCL pump following installation of a new source of bearing water on
December 16, WO 0211272.
b.
Findings
No findings of significance were identified.
1R20
Refueling and Other Outage Activities (71111.20)
a.
Inspection Scope
The inspectors observed activities and/or reviewed documents associated with the
Unit 1 refueling outage. The inspectors reviewed the outage plan and schedule in order
to verify that the shutdown risk had been adequately evaluated in accordance with the
licensees shutdown safety assessment procedures. The inspectors routinely reviewed
the licensees shutdown risk assessments comparing the licensees assessment to plant
equipment configuration and procedural requirements for shutdown risk assessments.
During this review, the inspectors also reviewed the capability of plant equipment to
perform critical safety functions. The inspectors also observed portions of the fuel
handling operations in containment, in the spent fuel pool, and in the control room. The
inspectors verified that the licensee performed these activities in accordance with TSs
and approved fuel handling procedures. The inspectors conducted a containment
cleanliness inspection near the end of the outage to verify that no material remained in
containment that could impair flow to the containment recirculation sump.
b.
Findings
No findings of significance were identified.
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors observed selected surveillance tests and/or reviewed test data to verify
that the equipment performance met surveillance procedure (SP) acceptance criteria.
The inspectors verified that the tested equipment was capable of performing its intended
safety functions as described in TSs and the USAR. The inspectors verified that the
testing met the required TS frequency; that the tests were conducted in accordance with
the applicable procedures; that operators met prerequisites and established the proper
plant conditions; and that the results of the tests were properly reviewed and recorded.
25
In addition, the inspectors reviewed several ARs to verify that the licensee was
identifying surveillance problems at an appropriate threshold, and that corrective actions
commensurate with the significance of the issue were identified and implemented. A
detailed list of the documents reviewed during this inspection is included at the end of
the report.
The following tests were observed and/or evaluated:
Unit 1 RCS Bolting Inspection, SP 1392, on November 16, 2002;
Unit 2 Integrated Safety Injection Test with Simulated Loss of Offsite Power,
SP 1083, on November 17;
Safety Injection Check Valve Test (Head Off) Part B: Refueling Water Storage
Tank (RWST) to RHR Flow Path Verification, SP 1092B, on November 20;
SI Check Valve Test (Head Off) Part A: High Head SI Flow Path Verification,
SP 1092A, on November 21;
Core Inventory Verification, SP 1177, on November 25;
D2 Diesel Generator Monthly Slow Start Test, SP 1305, and D2 Diesel
Generator 18-Month 24-Hour Load Test, SP 1335, on November 25 - 26;
Reactor Protection Logic Time Response Test, SP 1008, on December 2;
Safety Injection Check Valve Test (Head On) Part D, SP 1092D, and Turbine
Building Cooling Water Header Isolation SI Relays 1SI-12X and 1SI-22X Contact
Verification Test, SP 1126, on December 2 - 3;
Unit 1 Containment Coating Inspection, SP 1834, on December 4;
Reactor Coolant System Integrity Test, SP 1070, on December 4; and
Post-Outage Containment Close-Out Inspection, SP 1750, on December 5.
b.
Findings
No findings of significance were identified.
1R23
Temporary Plant Modifications (71111.23)
.1
Temporary Modification 02T131 Temporary Pipe Patch on a Pinhole Leak in Line
14-ZX-6
a.
Inspection Scope
On October 3, 2002, the inspectors reviewed Temporary Modification 02T131 that
installed a temporary pipe patch on a pinhole leak in line 14-ZX-6, the cooling water
supply line to Unit 1 and Unit 2 . The cooling water line itself was not considered a
risk significant component; however, the location of the leak was in close proximity to a
480-volt motor control center (MCC) that provided power to risk significant mitigating
system components. Due to the close proximity of the patch to the safety-related MCC,
the inspectors considered this temporary modification appropriate for inspection since it
could adversely affect the availability, reliability, or functional capability of risk significant
mitigating system components powered from the MCC.
The inspectors reviewed the associated 10 CFR 50.59 safety evaluation screening,
comparing it with system design basis requirements in the USAR. The inspectors
26
discussed the installation of the pipe patch with design engineers and compared the use
of the pipe patch temporary repair to Construction Code B-31.1 (1969) criteria.
b.
Findings
No findings of significance were identified.
.2
Temporary Modification 02T147 Temporary Pipe Clamp on the Instrument Air Supply
Header to the Unit 2 Containment
On October 22, 2002, an air leak was discovered on the 2-inch instrument air header
that feeds the Unit 2 containment. The air leak was caused by degradation of a solder
joint between supply piping and an adjacent elbow. The licensee installed a pipe clamp
as a preventive measure to preclude separation of the pipe from the elbow if solder joint
integrity were to further degrade.
On October 31, the inspectors reviewed Temporary Modification 02T147, which was
used for installation of the clamp on the header. The inspectors reviewed the
associated 10 CFR 50.59 safety evaluation screening, comparing it with system design
basis requirements in the USAR. The inspectors discussed the installations of the pipe
clamp with the system engineer and conducted a visual inspection of the pipe clamp
installation to assess if its installation adversely affected availability, reliability, or
functional capability of the instrument air supply to the Unit 2 containment.
b.
Findings
No findings of significance were identified.
1EP4
Emergency Action Level and Emergency Plan Changes (71114.04)
a.
Inspection Scope
The inspector reviewed Revision 24 of the Prairie Island Plants Emergency Plan to
determine whether changes identified reduced the effectiveness of the licensees
emergency planning, pending onsite inspection of the implementation of these changes.
b.
Findings
No findings of significance were identified.
1EP6
Drill Evaluation (71114.06)
a.
Inspection Scope
The inspectors observed the licensee perform an emergency preparedness drill on
October 23, 2002. The inspectors observed activities in the control room simulator. The
inspectors also attended the post-drill facility critique for the control room simulator
immediately following the drill and reviewed the final drill critique report. The inspectors
focused on weaknesses and deficiencies in the drill performance and ensured that the
27
licensee evaluators noted the same weaknesses and deficiencies and entered them into
the corrective action program. The inspectors placed emphasis on observations
regarding event classification, notifications, protective action recommendations, and site
evacuation and accountability activities. As part of the inspection, the inspectors
reviewed the drill package listed at the end of this report.
b.
Findings
No findings of significance were identified.
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1
Plant Walkdowns
a.
Inspection Scope
The inspectors performed walkdowns of the radiologically controlled area (RCA) to verify
the adequacy of radiological boundaries and postings. Specifically, the inspectors
performed confirmatory radiation measurements in the Unit 1 containment and auxiliary
and waste buildings to verify that radiologically significant work areas (high radiation
areas (HRAs), radiation areas, and airborne radioactivity areas) were properly posted
and controlled in accordance with 10 CFR Part 20 and the licensees procedures.
Additionally, the inspectors reviewed practices during the ongoing refueling outage for
controlling access to contaminated areas and for posting and controlling airborne
contamination areas to determine if controls were acceptable. During this review, the
inspectors evaluated the adequacy of the dose assessments for any actual internal
exposures greater than 50 millirem committed effective dose equivalent.
b.
Findings
No findings of significance were identified.
.2
High Risk Significant, High Dose Rate HRA and Very High Radiation Area (VHRA)
Controls
a.
Inspection Scope
The inspectors reviewed the licensees controls for access to risk significant HRAs and
VHRAs to ensure that the licensees controls were consistent with the requirements in
10 CFR Part 20 and TSs. Specifically, the inspectors discussed the controls with the
radiation protection staff and reviewed applicable procedures. The inspectors also
performed walkdowns of the Unit 1 containment building to ensure adequate posting
and locking of entrances to high dose rate (>25 rem in one hour at 30 centimeters)
28
b.
Findings
No findings of significance were identified.
.3
Problem Identification and Resolution
a.
Inspection Scope
The inspectors reviewed condition reports completed during the previous six months
which identified issues in radiation worker and radiation protection technician
performance. The inspectors reviewed these documents to assess the licensees ability
to identify repetitive problems, contributing causes, the extent of conditions, and to
implement corrective actions which would achieve lasting results.
b.
Findings
No findings of significance were identified.
2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls (71121.02)
.1
Radiological Work/ALARA Planning
a.
Inspection Scope
The inspectors examined the stations procedures for radiological work/ALARA
planning and scheduling, and evaluated the dose projection methodologies and
practices implemented for the 2002 Unit 1 refueling outage to verify that sound
technical bases for outage dose estimates existed.
The inspectors reviewed the exposure results and ALARA reviews for selected refueling
outage activities to evaluate the accuracy of exposure estimates in the ALARA plans.
The inspectors compared the actual exposure results versus the initial exposure
estimates, the estimated and actual dose rates, as well as the estimated and actual
man-hours expended. The inspectors reviewed the exposure history for each activity
and evaluated management involvement in exposure tracking to assess outage dose
performance and dose management practices. The inspectors reviewed selected work-
in-progress ALARA reviews to determine if additional engineering/dose controls for
those activities were necessary, and if required corrective action documents had been
generated. Those work activities included:
Unit 1 SG manway removal;
Unit 1 SG nozzle dam installation;
SG diaphragm hot particle retrieval;
selected inservice inspection (ISI) work;
removal of insulation; and
assembling and disassembling of scaffolding.
29
b.
Findings
No findings of significance were identified.
.2
Verification of Exposure Estimate Goals and Exposure Tracking System
g.
Inspection Scope
The inspectors reviewed the methodology and assumptions used by the licensee for
developing refueling outage exposure estimates and exposure goals. Actual job
exposure data was compared with estimates to verify that the licensee could project
and, thus, control radiological exposure. The inspectors also reviewed the licensees
exposure tracking system to verify that the level of exposure tracking detail, exposure
report timeliness, and exposure report distribution were sufficient to support control of
collective exposures. The inspectors evaluated how the licensee had identified
problems with its exposure estimates for some jobs, the processes being utilized to
revise dose estimates, and methods to improve its dose forecasting procedures to verify
that the licensee could adequately track dose.
b.
Findings
No findings of significance were identified.
.3
Job Site Inspections and ALARA Controls
a.
Inspection Scope
The inspectors observed work activities in the RCA that were performed in radiation
areas or HRAs to evaluate the use of ALARA controls. Specifically, the inspectors
assessed the implementation of radiation work permits, engineering and ALARA
controls, and radiological surveys, and observed pre-job radiological briefings (as
available) and radiation protection technician performance for the following Unit 1
refueling work activities:
Unit 1 SG manway removal;
Unit 1 SG nozzle dam installation;
SG diaphragm hot particle retrieval; and
selected inservice inspection work.
The inspectors also observed radiation worker performance to verify that the training
and skill levels demonstrated by the workers was sufficient with respect to the
radiological hazards present and the work involved. The inspectors evaluated workers
use of low dose waiting areas and the level of on-the-job supervision to ensure that
ALARA requirements were met.
b.
Findings
No findings of significance were identified.
30
.4
Problem Identification and Resolution
a.
Inspection Scope
The inspectors reviewed self-assessments, audits, and condition reports completed
during the previous four months which focused on ALARA planning and controls and the
radiological source term reduction program. The inspectors reviewed these documents
to assess the licensees ability to identify repetitive problems, contributing causes, the
extent of conditions, and to implement corrective actions which will achieve lasting
results.
b.
Findings
No findings of significance were identified.
3.
SAFEGUARDS
Cornerstone: Physical Protection
3PP3
Response to Contingency Events (71130.03)
a.
Inspection Scope
The Office of Homeland Security developed a Homeland Security Advisory System
(HSAS) to disseminate information regarding the risk of terrorist attacks. The HSAS
implements five color-coded threat conditions with a description of corresponding
actions at each level. NRC Regulatory Information Summary (RIS) 2002-12a, dated
August 19, 2002, NRC Threat Advisory and Protective Measures System, discusses
the HSAS and provides additional information on protective measures to licensees.
On September 10, the NRC issued a Safeguards Advisory to reactor licensees to
implement the protective measures described in RIS 2002-12a in response to the
Federal government declaration of threat level Orange. Subsequently, on
September 24, the Office of Homeland Security downgraded the national security threat
condition to Yellow and a corresponding reduction in the risk of a terrorist threat.
The inspectors interviewed licensee personnel and security staff, observed the conduct
of security operations, and assessed licensee implementation of the threat level
Orange protective measures. Inspection results were communicated to Region III and
Headquarters security staff for further evaluation.
b.
Findings
No findings of significance were identified.
31
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
Cornerstones: Mitigating Systems, Barrier Integrity, and Occupational
Radiation Safety
a.
Inspection Scope
The inspectors reviewed the performance indicator data submitted by the licensee for
completeness and accuracy, and to verify that the licensee had reported data in
accordance with the guidance provided by the Nuclear Energy Institute (NEI). The
inspectors reviewed documents listed at the end of this report for performance indicator
data for mitigating systems and barrier integrity cornerstones. The inspectors reviewed
the following performance indicators from the 3rd quarter 2001 through the 2nd quarter
2002:
Reactor Coolant System Leak Rate on October 11, 2002; and
Safety System Unavailability - Emergency Alternating Current (AC) Power
System on October 24, 2002.
Under the occupational radiation safety cornerstone, the inspectors verified the
licensees assessment of its performance indicator for occupational radiation safety.
One reportable element was identified by the licensee for the 2nd quarter of 2002. The
inspectors selectively reviewed the licensees data elements to verify that there were no
additional occurrences during the 4th quarter of 2001 and the first three quarters
of 2002.
b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
.1
Routine Review of Identification and Resolution of Problems
a.
Inspection Scope
As discussed in previous sections of this report, the inspectors routinely reviewed issues
during baseline inspection activities and plant status reviews to verify that they were
being entered into the licensees corrective action system at an appropriate threshold,
that corrective actions were performed in a timely manner, and that adverse trends were
identified and addressed. Minor issues entered into the licensees corrective action
system as a result of inspectors observations are generally denoted in the report.
b.
Findings
No findings of significance were identified.
32
.2
Licensee Resolution of Issues Associated With Unit 1 Emergency Diesel Generators
a.
Inspection Scope
On October 1, 2002, the inspectors reviewed the actions taken by the licensee to
resolve URI 50/282-01-10-01. This issue dated back to May 16, 2001, and was
concerned with the resolution of inadequacies identified in Prairie Island calculations
ENG-PI-002, Probabilistic Risk Assessment of D1 EDG [emergency diesel generator]
Room Door Vulnerability to Tornado Missile, and ENG-PI-005, Tornado & Seismic
Evaluation of D1/D2 Components. The inspectors assessed whether the timeliness of
the licensees corrective actions to resolve this issue were commensurate with the
safety significance of the issue. The inspectors reviewed USAR and IPEEE sections
discussing tornado hardness and seismic qualification for the Unit 1 EDGs and their
associated structures, discussed probabilistic risk assessment results assuming that
both Unit 1 EDGs and all connections to offsite power are lost during a tornado event
with plant risk engineers, and discussed probabilistic risk assessment results with the
Region III Senior Reactor Analyst. The inspectors also reviewed the licensees timeline
for correction of the inadequacies in the above referenced calculations.
b.
Findings
No findings of significance were identified. Based on licensee corrective actions
currently in progress, the inspectors consider URI 50/282-01-10-01 closed.
4OA3 Event Followup (71153)
a.
Inspection Scope
The purpose of this inspection was to assess Prairie Islands emergency preparedness
response during a seismic event which occurred on November 3, 2002. The inspectors
reviewed the operators response to this unplanned event and compared their actions to
the actions specified in annunciator response procedures, abnormal operating
procedures, and the emergency plan and implementing procedures.
b.
Findings
Introduction
The inspectors identified that the licensee failed to classify and declare an Unusual
Event in accordance with emergency plan implementing procedures following receipt of
the Seismic Event annunciator with confirmation of the occurrence of an earthquake in
Alaska. The finding was considered to be of very low safety significance (Green) and
was determined to be a Non-Cited Violation.
Discussion
On November 3, 2002, a seismic alarm was received in the control room. The licensee
entered Abnormal Operating Procedure AB-3 and confirmed the occurrence of the
Alaskan earthquake by contacting the National Earthquake Information Center in
33
Boulder, Colorado. The control room seismic monitor energized, the Seismic Event
annunciator was received, and magnetic tape operation initiated. However, a failure of
the seismic monitor chart paper recorder to produce a visible indication on its chart
paper prevented the timely evaluation of the peak acceleration experienced during the
event. Additionally, the failure of operators to follow the emergency plan implementing
procedure for event classification prevented classification and declaration of the event.
Abnormal Operating Procedure AB-3, Attachment B, directed operators to remove the
paper chart from the seismic recorder; determine the peak acceleration of the seismic
event; compare the peak acceleration recorded to the acceleration definitions for the
Seismic Event, Operational Basis Earthquake, and Design Basis Earthquake; and
declare the appropriate emergency action level if necessary. When operators removed
the chart paper from the seismic recorder they were unable to read markings on the
paper and were unable to promptly determine the peak acceleration of the event. This
problem was entered into the corrective action program with AR CAP 026100.
The inability to promptly determine peak acceleration resulted in the inability to complete
AB-3, Attachment B. Referring to Step 5.0 of Attachment A of AB-3, operators directed
instrument maintenance and engineering personnel to evaluate the magnetic tape
recorders. Five hours after the initial indication of the earthquake was received,
instrument maintenance and engineering personnel determined the peak acceleration
reached during the seismic event was 1 percent of the acceleration due to gravity (g).
Operators determined that no emergency action levels were reached and exited AB-3.
The licensee recognized the excessive amount of time needed to determine the peak
acceleration of the seismic event and entered the condition into their corrective action
The licensee declared the seismic monitor inoperable and commenced troubleshooting
activities. The inspectors discussed with instrument maintenance personnel the failure
of the seismic monitor chart recorder to produce a readable indication of the seismic
activity. The inspectors were told that the chart recorder was the light beam
galvanometer type and required ultra-violet light sensitive paper to be exposed. The
inspectors inquired as to the age of the paper installed in the seismic monitor with
respect to its shelf life and was told that there was no shelf life on the paper. After
additional prompting by the inspectors and consultation with the manufacturer of the
paper, the licensee confirmed that the paper did indeed have a shelf life and the paper
installed in the seismic monitor at the time of the event was beyond its 5-year shelf life.
The supply chain manager told the inspectors that the paper had not been included in
the sites shelf life program. The inspectors identified that the licensee had failed to
properly maintain the seismic monitoring equipment. The licensee ordered, received,
and installed new ultra-violet sensitive paper into the seismic monitor. The seismic
monitor was satisfactorily tested following the installation of the new paper. The
corrective actions for this condition were documented in condition evaluation
(CE) 001350.
The inspectors reviewed the annunciator response procedures 47023-603 and C81000
for the Seismic Event alarm. The inspectors noted that the annunciator response
procedure C81000 indicated that the instrument setpoint for the Seismic Event alarm
was 3 percent of the acceleration due to gravity (g) in the vertical or horizontal
34
directions. Analysis of the seismic monitor magnetic tapes showed only a 1 percent g
peak acceleration indicating the alarm setpoint was set low in the conservative direction.
Instrument maintenance personnel told the inspectors that the seismic monitor had been
recently calibrated.
The inspectors reviewed operator actions with respect to the emergency plan
implementing procedure F3-2, Classification of Emergencies. The inspectors reviewed
the operator control room log entries for November 3, 2002, from 4:31 p.m. through
9:31 p.m., noting that the operators only entered the annunciator response procedures
C81000 and 47023-603, and abnormal operating procedure AB-3. No log entries were
noted that indicated the operators entered F3-2, Attachment 1, Condition 19a,
Earthquake. Procedure AB-3, Attachment A, would have directed the operators to
enter F3-2, Attachment 1, Condition 19a, if the seismic monitor paper chart would have
functioned properly allowing completion of AB-3, Attachment B, and a peak
acceleration of greater than or equal to 3 percent g was recorded during the seismic
event. As mentioned previously, operators were unable to complete AB-3, Attachment
B, and AB-3, Attachment A, Step 2.0. Since Step 2.0 could not be completed, operators
skipped Steps 2.0, 3.0, and 4.0. Step 3.0 of AB-3 was the step that referred operators
to emergency plan implementing procedure F3-2 for event classification.
Operators should have entered F3-2, Attachment 1, Condition 19a, immediately after
the receipt of the Seismic Event alarm. F3-2 requires two conditions to be met
necessitating the declaration of an Unusual Event classification. The first condition was
the receipt of the Seismic Event annunciator on the seismic monitor. This condition was
met on receipt of the alarm at 4:31 p.m. The second condition to confirm the seismic
event by one or more offsite sources was met when the licensee confirmed the event
with the National Earthquake Information Center in Boulder, Colorado at 4:40 p.m. The
inspectors identified that the licensee failed to follow its emergency plan implementing
procedure for this event. The licensee entered the issue into their corrective action
program as Other (OTH) 023756. This document specified an evaluation of the
licensees actions for the November 3, 2002, event.
The licensee told the inspectors that the operators did not enter F3-2 and classify the
event because they did not believe the event to be of sufficient magnitude to warrant an
unusual event declaration. Operators based their decision on the significant distance
between the plant site and the earthquakes epicenter, the absence of earth motion at
the plant site as sensed by on-shift plant personnel, and confirmation from the nearby
Monticello plant that the event was not detected on their seismic monitors. The
verification of seismic activity with the Monticello plant occurred approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />
after the Seismic Event annunciator was received.
The inspectors reviewed the licensees reasoning for not declaring the event and
determined that the actions taken by the licensee did not meet the timeliness
requirements for event classification and declaration. The regulations do not provide an
explicit time limit for classification but do imply that the classification should be made
without delay. An event classification time limit of 15 minutes has been accepted by
both the NRC and industry. In August of 1995, the NRC issued Emergency
Preparedness Position (EPPOS) Number 2, discussing NRC expectations for the
timeliness of the classification of emergency conditions. This expectation has been
35
further communicated in industry guidance. Nuclear Energy Institute 99-02, Section 2.4,
provided a definition of timely that stated that classifications are made consistent with
the goal of 15 minutes once plant parameters reach an Emergency Action Level. In this
case, plant parameters (i.e., the Seismic Event annunciator) reached a Emergency
Action Level at 4:31 p.m. The information possessed by the licensee at 4:46 p.m.
(15 minutes after the receipt of the Seismic Event annunciator) met all criteria for the
classification and declaration of an Unusual Event and, therefore, should have been
declared at that time.
The inspectors also identified that the procedural guidance contained in AB-3 and
F3-2 conflicted. For example, following AB-3, operators must receive a seismic monitor
alarm, verify the magnitude of the peak acceleration, and confirm the event with at least
one off-site source; whereas, following F3-2, operators need only to receive a seismic
monitor alarm and confirm the event with at least one off-site source before declaring an
Unusual Event. The issue of conflicting procedural guidance was entered into the
corrective action program with AR CAPs 027232 and 027233.
Analysis
The inspectors determined that this event did not have any actual safety consequences
or potential for impacting NRCs regulatory function. However, the licensees failure to
make an emergency classification was considered more than minor since it affected an
Emergency Preparedness Cornerstone objective. The affected objective is the
emergency response organizations performance in an event to ensure that Prairie
Island is capable of implementing adequate measures to protect public health and
safety during an emergency.
Consequently, this issue represents a finding that is more than minor and which was
evaluated using the Emergency Preparedness Significance Determination Process
contained in Appendix B to Manual Chapter 0609. Since the finding involved a failure
to meet a regulatory requirement, but did not represent a failure to meet the planning
standards of 10 CFR 50.47(b) or those of Appendix E to 10 CFR Part 50, the finding
was determined to be of very low safety significance (Green).
Enforcement
In part, 10 CFR 50.54(q), 50.47(b)(4), Sections IV.B and IV.D.3 of Appendix E of
10 CFR Part 50 require that an emergency classification declaration be made promptly
after an emergency action level is met. Contrary to the above, the licensee failed to
classify and declare an Unusual Event on November 3, 2002, when all required
conditions necessitating classification and declaration of an Unusual Event were met.
Since the licensee entered the conditions identified by the inspectors into their corrective
action program with OTH 023756, this violation is being treated as an NCV in
accordance with VI.A.1 of the NRCs Enforcement Policy (NCV 50-282/306/02-09-05).
36
4OA5 Other Activities
.1
Reactor Pressure Vessel Head and Vessel Head Penetration Nozzles (Temporary
Instruction (TI) 2515/150)
a.
Inspection Scope
On August 9, 2002, the NRC issued Bulletin 2002-02, Reactor Pressure Vessel Head
and Vessel Head Penetration Nozzle Inspection Programs. The purpose of this
Bulleting was to: (1) Advise pressurized water reactor (PWR) licensees that visual
examinations, as a primary inspection method for reactor pressure vessel head and
vessel head penetration (VHP) nozzles, may need to be supplemented with additional
measures; (2) Advise PWR licensees that inspection methods and frequencies to
demonstrate compliance with applicable regulations should be demonstrated as
effective and reliable; (3) Request information from all PWR addressees concerning the
reactor pressure vessel (RPV) head and VHP nozzle inspection programs; and
(4) Require all PWR addressees to provide written responses to this bulletin related to
their inspection program plans.
The objective of TI 2515/150, Reactor Pressure Vessel Head and Vessel Head
Penetration Nozzles, was to implement an on-site NRC review of the licensees
activities in response to NRC Bulletin 2002-02. Specifically, licensee procedures,
equipment, and personnel used for VHP examinations were evaluated by the inspectors
to confirm that the licensee met commitments associated with Bulletin 2002-02.
From November 18 through November 26, 2002, the inspectors performed a review of
the licensees activities in response to commitments made to NRC Bulletin 2002-02. In
response to Bulletin 2002-02, the licensee referred to previous commitments made in
response to Bulletin 2001-01, Circumferential Cracking of Reactor Pressure Vessel
Head Penetration Nozzles. In response to Bulletin 2001-01, the licensee committed to
perform an effective visual examination of the vessel head and penetration nozzles.
To assess the licensees efforts in conducting an effective visual examination of the
RPV head and VHP nozzles, the inspectors:
performed an independent direct visual examination of the nozzle-to-head
interface for portions of 20 VHPs;
observed the licensees visual examination of the VHPs;
interviewed nondestructive examination personnel;
reviewed the head inspection work order; and
reviewed the head inspection examination results.
Additionally, the inspectors reviewed the licensees VHP nozzle susceptibility ranking
calculation to:
verify that appropriate plant-specific information was used as input;
confirm the basis for the head temperature used by licensee; and
determine if previous VHP cracks had been identified and if so, used in the
susceptibility ranking calculation.
37
b.
Observations
Summary
The licensee did not identify any leaking VHP nozzles. The licensee identified three
nozzles with white deposits at the VHP nozzle-to-head interface which were not
considered indications of VHP leakage.
Evaluation of Inspection Requirements
In accordance with requirements of TI 2515/150, the inspectors evaluated and
answered the following questions:
1.
Was the examination:
a.
Performed by qualified and knowledgeable personnel? (Briefly describe the
personnel training/qualification process used by the licensee for this activity.)
Yes. The licensee conducted a direct visual examination of the head with a
knowledgeable staff member certified to Level II as a VT-2 examiner in
accordance with programs meeting the American Society for Nondestructive
Testing Recommended Practice SNT-TC-1A.
b.
Performed in accordance with approved procedures?
No. The licensee conducted direct visual examinations in accordance with
requirements of a reviewed and approved work order (WO 0200959, Inspect RV
[reactor vessel] Head Penetrations for Leakage). The use of a work order was
consistent with licensee commitments to Bulletin 2001-01. The licensee
acceptance criteria established in this work order included the lack of any
relevant indications of the type described in Electric Power Research Institute
TR-1006899, Visual Examination for Leakage of PWR Reactor Head
Penetrations on Top of RPV Head. The inspector concluded that this criterion
was consistent with the licensees commitment to Bulletin 2001-01, which stated
no visual indications of cracks or leaks. The licensees visual inspection scope
was not explicitly defined in the work order. The work order required the
licensee inspection personnel to document the examination coverage on an
attached worksheet. The inspectors confirmed that the licensee had not
committed to complete a 360 degree visual examination of each penetration
nozzle.
The inspectors identified that the work order did not implement visual
examination quality standards such as those described for visual VT-1, VT-2,
and VT-3 examinations in Section XI of the ASME Code. Based on this
observation, the licensee changed the work order to implemented a visual quality
check for this examination that included resolution of a 1/32 black line on an
18-percent neutral gray card (visual acuity card). The work order did not specify
at what distance the licensees inspector was required to resolve the line on the
visual acuity card. The inspectors noted that the licensee inspector was able to
38
resolve this line at distances in excess of five feet. Specifically, the licensee
inspector mounted the visual acuity card on a pole and placed it on the vessel
head with the portable lighting used during the head examination and was able
to resolve the line.
c.
Able to identify, disposition, and resolve deficiencies?
Yes. Based on direct observation of the head and penetration nozzles, the
inspectors concluded that the lighting and access for the visual examination was
adequate to detect boric acid deposits. The licensees examinations identified
three locations (D-12, D-10 and I-11) with white deposits at the VHP nozzle-to-
head interface. The licensee characterized these deposits as white flakes and
fluffy-yellow/white deposits. The size of two deposit particles was recorded as
1/4- by 1/16-inch and 1/16- by 1/16-inch. The licensee subsequently removed
these deposits with a vacuum. Because of the small size and the loose/readily
removable nature of these deposits, the licensee did not consider the deposits to
be indicative of leakage. The licensee documented the vessel head inspection
results in the corrective action system (CAP 026636).
d.
Capable of identifying the primary water stress corrosion cracking phenomenon
described in the bulletin?
Yes. The inspectors determined through direct observations, interviews with
inspection personnel, and reviews of the work order and examination reports that
the licensees efforts were capable of detecting and characterizing leakage from
cracking in VHP nozzles. The inspectors determined that the inspection
personnel had access to each of the head penetrations (40 total) and head vent
nozzle.
2.
What was the condition of the reactor head (debris, insulation, dirt, boron from
other sources, physical layout, viewing obstructions)?
The reactor head was covered with reflective metal insulation panels installed on
a support structure over the top of the reactor head. The insulation was
nominally 3 inches thick and was composed of layers of thin stainless steel
sheets. Clearance between the head and insulation was approximately 1 inch at
the center and 18 inches at the outside nozzles. The insulation structure
included four rectangular view ports (5.5 inches by 16 inches), which allowed the
licensee access to the bare metal head. The inspector confirmed that most
nozzles were readily visible through these viewing ports and that the head was
relatively free of debris which would hinder an effective visual examination. With
the aid of a mirror, the licensees inspection staff were able to obtain a 360-
degree visual examination of each VHP nozzle-to-head interface through these
viewing ports. However, the inspectors could not confirm that the licensee had
sufficient access to penetration nozzle L-10 to permit a 360-degree inspection.
This nozzle was in close proximity to the vertical reflective metal head insulation
panel on the downhill side. The licensees inspector considered that his
inspection was adequate to have detected leakage with the penetration in this
configuration.
39
The licensees examinations identified three locations (D-12, D-10 and I-11) with
white deposits at the VHP nozzle-to-head interface (CAP 026636). The
inspectors questioned if these deposits would obstruct or mask leakage deposits
at the VHP nozzle-to-head interface. The licensees inspector did not consider
that these deposits would mask any leakage deposits because leakage deposits
would be tightly adherent and would remain at the interface following removal of
the loose deposits with a vacuum. The inspectors observed VHP nozzle D-12
(with white deposits) prior to, and after vacuum cleaning. The inspectors did not
see any deposits remaining at the VHP nozzle-to-head interface following
cleaning.
3.
Could small boron deposits, as described in Bulletin 2001-01, be identified and
characterized?
Yes. The inspectors determined through direct observations, interviews with
inspection personnel, and reviews of the work order and examination reports that
small boron deposits, as described in the Bulletin 2001-01, could be identified
and characterized.
4.
What material deficiencies (associated with the concerns identified in the
bulletin) were identified that require repair?
None. The licensee did not identify any materiel deficiencies associated with the
40 VHP nozzles or head vent nozzle that were considered indicative of leakage.
Thus, the licensee did not identify material deficiencies associated with concerns
identified in the bulletin which required repair.
5.
What, if any, significant items that could impede effective examinations?
The inspectors did not identify any significant items which would impede an
effective visual examination.
Nozzle Susceptibility Ranking Calculation
The licensee performed Calculation ENG-ME-535 to determine the effective degradation
years (EDY) for the VHP nozzles in Units 1 and 2. In Bulletin 2002-02, the EDY is used
as a basis to establish appropriate inspection programs for VHP nozzles based on
increasing susceptibility to nozzle cracking with increasing EDY. For Unit 1, the licensee
calculated an EDY of 10.58 years through September of 2002. Based on this EDY and
the guidance on acceptable inspection programs discussed in Bulletin 2002-02, the
licensee chose to perform a visual examination of the head during this refueling outage.
The inspectors confirmed that the formula used by the licensee in Calculation
ENG-ME-535 was identical to the formula discussed in Bulletin 2002 to calculate EDY.
As an input to Calculation ENG-ME-535, the licensee used a normal operating reactor
vessel head temperature of 580.2 degrees Fahrenheit (F). This temperature was
taken from Table 5-2 in a proprietary Westinghouse document WCAP 14918,
Probabilistic Evaluation of Reactor Vessel Closure Head Penetration Integrity for Prairie
Island Units 1 and 2. The licensee did not have any records onsite to confirm the
40
inputs used by the vendor in determining the vessel head temperature. The licensee
subsequently entered this issue into the corrective action program CAP 026603 and
initiated Engineering Work Request (EWR) 0036068, Heat Temperature Input to Calc
ENG-ME-535," to obtain appropriate documentation.
The inspectors questions about the input temperature used in the calculation prompted
the licensee to contact Westinghouse, who identified that the 580.2 F head
temperature was based, in part, on Calculation Note EMT-97-78. This calculation used
a computer program (THRIVE) to determine upper bulk mean fluid temperature of the
vessel head area for use in loss-of-coolant accident analysis blowdown load
calculations. For that application, the Westinghouse had used a cold leg temperature of
527 F vice the actual in-plant measured value of 530 F. Westinghouse reported that
the output of this calculation performed in 1992 for the upper bulk mean fluid
temperature was 577.2 F. Westinghouse then added 3 F to adjust for the plant
specific cold leg temperature difference to obtain the 580.2 F value used in WCAP
14918 and as the input value for head temperature in Calculation ENG-ME-535.
In addition to the EDY, an acceptable VHP inspection program was based on
whether the licensee had identified cracks or leakage during previous inspections of
VHP nozzles. Based on discussions with licensee inspection personnel, the inspectors
confirmed that no indications of VHP nozzle leakage had been identified during previous
Unit 1 head inspections. However, the licensee inspector reported that a complete
360 degree visual examination of each VHP nozzle-to head interface had not been
performed during the previous Unit 1 visual examination.
c.
Findings
No findings of significance were identified.
.2
Completion of TI 2515/149, Mitigating Systems Performance Index (MSPI) Pilot
Verification
From November 25 through December 20, 2002, the inspectors completed the
requirements of the TI to verify that the licensee had correctly implemented the MSPI
pilot guidance for reporting unavailability and unreliability of the monitored safety
systems. Documents reviewed during this inspection are listed at the end of this report.
The detailed results of this inspection are documented in a memorandum included as an
attachment to this report.
.3
Completion of Appendix A to TI 2515/148, Inspection of Nuclear Reactor Safeguards
Interim Compensatory Measures, Revision 1
The inspectors completed the pre-inspection audit for interim compensatory measures
at nuclear power plants, dated September 13, 2002.
4OA6 Meeting(s)
.1
Interim Exit Meetings
41
Results of Licensed Operator Requalification Testing for Calender Year 2002 and
Applicability of NRC IMC 0609, Appendix I, Operator Requalification Human
Performance Significance Determination Process, with Mr. T. Bacon on November 14,
2002.
Access Control to Radiologically Controlled Areas and ALARA inspection with Mr. M.
Nazar on November 22.
TI 2515/150 and inservice inspection (IP 7111108) with Mr. M. Nazar on November 26.
.2
Exit Meeting
The resident inspectors presented the inspection results to Mr. M. Nazar and other
members of licensee management on January 13, 2003. The inspectors asked the
licensee whether any materials examined during the inspection should be considered
proprietary. No proprietary information was identified.
4OA7 Licensee-Identified Violations
The following violations of very low significance were identified by the licensee and are
violations of NRC requirements which meets the criteria of Section VI of the NRC
Enforcement Manual, NUREG-1600, for being dispositioned as NCVs.
Cornerstone: Mitigating Systems
.1
Missed Technical Specification Surveillance Test
Technical Specification Condition 3.7.8.A, Cooling Water System, states that with
no safeguards cooling water pumps operable in one train, then on Unit 1 enter the
applicable conditions of the required actions of the Limiting Condition for
Operation 3.8.1, AC Sources. Technical Specification Condition 3.8.1.A states that
surveillance requirement (SR) 3.8.1.1 shall be performed within one hour and every
eight hours thereafter. On October 26, 2002, the licensee identified that they had failed
to meet these requirements on October 24, when the 22 safety-related DDCL pump was
declared inoperable for planned maintenance. Upon discovery of the missed
surveillance activity, the licensee performed and successfully completed SP 1118,
Verifying Paths from the Grid to Unit 1 Buses, and conducted an investigation that did
not identify any degradations in the offsite alternating current power sources. The
finding was determined to be of very low safety significance since it did not result in any
actual loss of safety function. This issue was entered into the licensees corrective
action program with AR CAP 025986.
.2
Inoperable RHR Suction Relief Valve
The Design Basis Document (DBD) System 15, Residual Heat Removal System,
requires that the RHR system be protected from over-pressure in accordance with the
ASME Boiler and Pressure Vessel Code, 1968 Winter. Relief Valve RH-8-1 was
intended to perform this function on Unit 1. However, on November 18, 2002, the
42
licensee identified that RH-8-1 had been gagged and was not able to perform its
pressure relief function. The valvess work history indicated that it had been gagged
since its installation in April 1999. The installation of the gagging device on RH-8-1
constituted a change to the design of the RHR system as described in its design basis
and was inconsistent with the design control requirements of 10 CFR 50, Appendix B,
Criterion III. The finding was determined to be of very low safety significance since at
no time did RHR system pressure approach the piping design pressure nor did it result
in non-compliance with low temperature over-pressure protection TSs, increase the
likelihood that a loss of decay heat removal would occur, increase the likelihood that a
loss of RCS inventory would occur, increase the likelihood that a loss of offsite power
would occur, degrade the capability to terminate a leak path or add RCS inventory,
degrade the ability to recover decay heat removal once lost, degrade the ability to
establish an alternate core cooling path, or degrade the ability of containment to remain
intact following a severe accident. This issue was entered into the corrective action
43
KEY POINTS OF CONTACT
Licensee
T. Amundson, Manager Business Support
P. Huffman, Manager of System Engineering
J. Jensen, Production Planning Manager
A. Johnson, Radiation Protection Manager
J. Kivi, Licensing Engineer
R. Lingle, Operations Manager
M. McKeown, Manager of Design Engineering
M. Ladd, General Superintendent Plant Maintenance
M. Nazar, Site Vice President
S. Northard, Director of Engineering
J. Waddell, Superintendent Security
M. Werner, Plant Manager
P. Wildenborg, Lead Technical Health Physicist
R. Womack, Manager of Engineering Programs
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-282/306/02-09-01
Failure to Follow Internal Flood Control Procedure
(Section 1R06)
50-282/306/02-09-02
Missed UT Examinations for SG 12 and SG 21 W-A Welds
(Section 1R08.b.(1))
50-282/306/02-09-03
Lack of ASME Code Requirement in 3 UT procedures
(Section 1R08.b.(2))
50-282/306/02-09-04
Missed Technical Review for UT Procedure
(Section 1R08.b.(3))
50-282/306/02-09-05
Missed Emergency Classification and Declaration
(Section 4OA3)
Closed
50-282/306/02-09-01
Failure to Follow Internal Flood Control Procedure
(Section 1R06)
50-282/306/02-09-03
Lack of ASME Code Requirement in 3 UT Procedures
(Section 1R08.b.(2))
50-282/306/02-09-04
Missed Technical Review for UT Procedure
(Section 1R08.b.(3))
44
50-282/306/02-09-05
Missed Emergency Classification and Declaration
(Section 4OA3)
50-282/01-10-01
Ability of D1 and D2 Exhaust Lines to Survive a Design
Basis Tornado or Seismic Event (Section 4OA2.2)
50-282/306/02-08-02
Maintenance Rule Functional Failure Evaluation of Bypass
Gate Failures (Section 1R12.3)
Discussed
None.
45
LIST OF DOCUMENTS REVIEWED
1R01
Adverse Weather
Cold Weather Preparations
Test Procedure TP 1637; Winter Plant Operation; Revision 29
IPEEE, Appendix C; Assessment of Other External Events for Prairie Island
ENG-ME-178; Screenhouse Ventilation Evaluation Operating Procedure; Revision 0
C37.8; Screenhouse Safeguard Equipment Cooling Operating Procedure; Revision 7
C37.5; Screenhouse Normal Ventilation Operating Procedure; Revision 5
C25; Circulating Water System Operating Procedure; Revision 24
AR CAP 026024; Glycol System ZY Has Inadequate Antifreeze Protection;
October 29, 2002
AR CAP 025798; Auxiliary Building Make Up Air Handlers Tripping Off; October 16,
2002
AR CAP 025774; Possible Rework on 121 Administration Building Hot Water Circulating
Pump; October 15, 2002
WO 0100562; Enclose the Auxiliary Building Cooling Water Dump-to-Grade to Prevent
Ice Buildup
1R04
Equipment Alignment
12 DDCL Pump Partial Walkdown
TS 3.7.8; Cooling Water System; Amendment 158
USAR 10.4.1; Cooling Water System; Revision 24
C35; Cooling Water Operating Procedure; Revision 49
C1.1.35-1; Cooling Water System Unit One Integrated Checklist; Revision 8
C1.1.35-3; Cooling Water System Integrated Checklist; Revision 21
Cooling Water System Health Update; April 22, 2002
AR CAP 025178; 12 Diesel Driven Cooling Water Pump; September 12, 2002
AR CAP 025186; 12 DDCL Pump Fell in the Performance Curve Alert Range During the
9/12/02 Run; September 12, 2002
46
AR CAP 025837; 121 MDCLP [Motor-Driven Cooling Water Pump] per SP 1106C
Showed a Step Drop in Performance; October 17, 2002
21 Component Cooling Heat Exchanger Partial Walkdown
Integrated Checklist C1.1.14-2; Unit 2 Component Cooling System; Revision 23
WO 0209384; Oil Leak on 2CC-1-7; September 26, 2002
AR CAP 027285; Evaluate AWIs and Maintenance Standards Implementing Procedures
(MSIPs) to Ensure Consistent Requirements for Blocking Wheels; December 18, 2002
MSIP 1003; Use and Storage of Service Equipment; Revision 4W
Unit 1 Safety Injection Complete Walkdown
Plant Procedure B18A; Safety Injection System; Revision 4
TS 3.5.2 and Bases; Emergency Core Cooling Systems - Operating; Amendment 158
USAR 6.2; Safety Injection System; Revision 22
Operating Procedure C18; Engineered Safeguards System Unit 1; Revision 11
Integrated Checklist C1.1.18-1; SI [Safety Injection], CS [Containment Spray], CA
[Caustic Addition] & HC [Hydrogen Control] System Checklist Unit 1; Revision 41
Operating Procedure 1C1.2; Unit 1 Startup Procedure; Revision 29
5AWI 3.12.6; Fluid Leak Management Program; Revision 0
AR CAP 023138; Okonite/Scotch EQ Tape Splices Installed in Non-Tested
Configurations; April 17, 2002
WO 9407097; Wire Code Changes at MV-32162 11 SI Pump Suction;
November 16, 1994
WO 0200533; Body to Bonnet Leak on SI-10-1; January 17, 2002
WO 0203653; Boric Acid Residue on Cap for SI-20-37; April 17, 2002
WO 0203719; Install 11 SI Mini Recirc Line Flowmeter; April 25, 2002
WO 0203720; Install 12 Minimum Recirc Line Flowmeter; April 25, 2002
WOs 0206251, 0206252, 0206254, 0206255, and 0206258; Replace Okonite Splice
with EQ Qualified Splice; July 17, 2002
WO 0210039; Broken Drain Stem on Manifold Valve; October 14, 2002
1R05
Fire Protection
47
Area Walkdowns
Plant Safety Procedure F5, Appendix A; Fire Strategies for Fire Areas 86; Revision 7
IPEEE NSPLMI-96001 Appendix B; Internal Fires Analysis; Revision 2
Plant Safety Procedure F5, Appendix F; Fire Hazard Analysis for Fire Areas 86;
Revision 16
AR CAP 026044; Fire Door Requirements and Operability; October 30, 2002
1R06
Flood Protection Measures (Internal)
IPE NSPLMI-94001 Section 3.3.8; Internal Flooding Evaluation; Revision 0
DBD-TOP-05; Design Bases Document for Hazards; Revision 2
H36; Plant Flooding Procedure; Revision 0
5AWI 8.9.0; Internal Flooding Drainage Control; Revision 0
AR CAP 025766; Need Operability Evaluation for Non-Safeguards Cooling Water
Pumps; October 14, 2002
AR CAP 026010; Loose Oil Absorbent Materials Were Found in 22 Diesel Driven
Cooling Water Pump Room; October 28, 2002
GEN 200200252; Oil Absorbent Materials Were Found in the Vital Area of Plant
Screenhouse; January 9, 2002
AR CAP 026158; Temporary Power Cables Routed Through Critical Drainage Path
Without Evaluation; November 6, 2002
AR CAP 026291; Foreign Material in 121 Cooling Water Pump Room While Lined Up as
Safeguards Pump; November 13, 2002
CE 001406; Evaluate Past Operability Impact on the Cooling Water Pumps;
November 13, 2002
Apparent Cause Evaluation (ACE) 008603; Conduct ACE Regarding CAP 026291;
November 14, 2002
ENG-ME-458; Calculation of the Highest Acceptable Leak Rate in the Cooling Water
Pump Rooms; Revision 1
1R07
Heat Sink Performance
TS 3.7.7; Component Cooling Water System; Amendment 158
48
USAR, Section 10.4.2; Component Cooling Water System; Revision 24
DBD System 14; Component Cooling Water System; Revision 3
WO 0114307; Perform SP 1304 Unit 1 Component Cooling Water Heat Exchanger
Performance Test; November 16, 2002
SP 1304; Unit 1 Component Cooling Water Heat Exchanger Performance Test;
Revision 5
AR CAP 026355; Potential Silting/Sediment Concerns with Plant Equipment and
Systems; November 16, 2002
CE 001474; Evaluate and If Necessary Initiate Corrective Action Regarding
CAP 026355; November 19, 2002
EWR 003548; Determine If Additional Flushing Procedures for Auxiliary Building
Coolers is Desirable; December 18, 2002
EWR 003549; Evaluate Quarterly Flushing of Steam Generator Blowdown Heat
Exchangers; December 18, 2002
EWR 003550; Determine If It Is Desirable to Add Small Bore Vents and Drains to
Current Program; December 18, 2002
1R08
Inservice Inspection Activities
Audit
Observation Report 2002-004-6-010; October 30, 2002
Corrective Action Reports
AR CAP 026473; Mixed Residual Indications Not Evaluated for Voltage Based Repair
Criteria; November 19, 2002
AR CAP 023120; Errors Found in ISI Relief Request Submitted to NRC; April 15, 2002
AR CAP 023017; Reference Error in Prairie Island Technical Specification; April 3, 2002
AR CAP 024378; Tube Pull at Sequoia May Affect ODSCC ARC Curves; July 30, 2002
AR CAP 023573; Incorporate Updated In-Situ Screening Guidelines into H25.2;
May 21, 2002
AR CAP 025203; ISI Code Percentages Not Used for First Period of the Third Interval
for Category B-B Welds; September 13, 2002
AR CAP 012058; Reduced Internal Diameter of Four Sleeves in 12 SG;
October 30, 1997
49
AR CAP 0001588; RCS Leakage VT-2 Visual Examination Not Performed in
Accordance with ASME XI Code; September 14, 2001
AR CAP 000809; Primary Coolant Leakage Through SG Cold Leg Primary Manway
Cover; March 26, 2002
Condition Report 200201449; Eddy Current Testing Had to be Repeated in SG 21;
February 13, 2002
Condition Report 200100475; SG 12 Hot Leg Manway Leak; January 21, 2001
Corrective Action Process Reports Issued As a Result of Inspection Activities
AR CAP 026513; Three Non-Destructive Examination Procedures Do Not State Modes
of Wave Propagation as Required by the ASME Code; November 20, 2002
AR CAP 026514; Procedure ISI-UT-5E Was Not Periodically Reviewed; November 20,
2002
AR CAP 026563; Weld WA on SG-11 Was Not Scheduled for Successive Examinations
as Required; November 21, 2002
AR CAP 026603; Assess Head Temperature Used in EDY Calculation ENG-ME-535;
November 22, 2002
Code Replacement/Repair Activities
WO 0004477; Perform Preventative LCSW Buildup on RV Head; February 10, 2001
WOs 0100722, 0100505, 0003101; Loop B Pressurizer Spray Valve (CV 31225)
Replacement
Drawing
A-6733; Reactor Coolant Lines 111 and 113; March 4, 1971
Nondestructive Examination Reports
Radiograph Test report for WO 07F4188; February 7, 8, 9, 12, and 13, 2001
99-0143; Pipe-to-Elbow Weld W-21 Resistance Thermal Detector Take Off on Loop A
Cold Leg; May 4, 1999
99-0352; SG-11 Tube Sheet-to-Head Weld WA; May 24, 1999
99-0353; SG-11 Tube Sheet-to-Head Weld WA; May 24, 1999
2001P020; Reactor Coolant (RC) Pipe-to-Flange W-4; February 2, 2001
2002V216; RC Support H2; November 20, 2002
2002U055; RC Safe End-to-45 Degree Elbow Weld W-2; November 22, 2002
50
2002U056; RC 45 Degree Elbow-to-Pipe Weld W-3; November 22, 2002
2002U057; RC Reducer-to-Safe End Weld W-13; November 22, 2002
Procedures
MMRN 1.1; Reference Manual Policy and Administration; Revision 0
ISI-MT-1; Dry Powder Magnetic Particle Examination; October 18, 2001
ISI-PT-1; Solvent Removable, Visible Dye Penetrant Examination; October 18, 2001
ISI-UT-1A; Ultrasonic Examination of Ferritic Piping Welds to Appendix VIII;
November 2, 2001
ISI-UT-3; Ultrasonic Examination of Ferritic Vessels; August 14, 2002
ISI-UT-3A ; Ultrasonic Examination of Reactor Vessel Welds; January 5, 2000
ISI-UT-3B; Ultrasonic Examination of Reactor Vessel Welds to Appendix VIII;
October 10, 2001
ISI-UT-5D; Ultrasonic Examination of Pressurizer Nozzle Inner Radii; August 14, 2002
ISI-UT-5E; Ultrasonic Examination of Steam Generator Primary and Main Steam Nozzle
Inner Radii; October 6, 1997
ISI-UT-11; Ultrasonic Examination of Centrifugally Cast Stainless Steel Pipe;
August 14, 2002
ISI-UT-16; UT Examination of Welds in Austenitic and High Nickel Alloy Materials;
January 28, 2002
ISI-UT-16A; Ultrasonic Examination of Austenitic Piping Welds to Appendix VIII;
November 1, 2002
ISI-ET-1.0; Bobbin Coil Data Analysis Guidelines; February 6, 2002
ISI-ET-3.0; Multiple Rotating Pancake Coil Data Analysis Guidelines; January 9, 2002
H25.2; Steam Generator Condition Monitoring; Revision 8
H25.1; Assessment of SG Tube Degradation Mechanisms; July 26, 2002
PI-SG-01; In-Situ Pressure Test Using the Computerized Data Acquisition System;
Revision 1
WPS AO 8155; Gas Tungsten Arc Welding (GTAW) of Stainless Steel; July 10, 1996
51
WPS P8P8GTN0; GTAW Welding of P8 toP8 Materials Without Impacts;
December 10, 1999
Miscellaneous Documents
Letter from NSP [Northern States Power] to NRC; Unit 1, Cycle 19 Steam Generator
Tube Support Plate Voltage Based Repair Criteria 90-Day Report; March 13, 1998
Letter from NSP to NRC; Response to Generic Letter 97-05: Steam Generator Tube
Inspection Techniques; March 13, 1998
Letter from NSP to NRC; Response to Generic Letter 97-06: Steam Generator Internals
Degradation; March 30, 1998
Letter from NSP to NRC; Response to Generic Letter 95-03: Circumferential Cracking
of Steam Generator Tubes; June 27, 1995
Letter from NRC to NEI; Flaw Evaluation Criteria; September 24, 2001
Condition Monitoring and Operational Assessment of Steam Generator Tubing at Prairie
Island, Unit 1 Cycle 20; February 2001
Prairie Island Unit 2 Site Qualification Document; January 30, 2002
INCO Alloys International CMTR 100523; January 16, 2001
Weld Data Sheet 31004; January 25, 2001
Procedure Qualification Record A08202 3-1; October 28, 1998
Procedure Qualification Record A08202 3-2; October 28, 1998
Procedure Qualification Record A08202 3-3; January 8, 1998
Procedure Qualification Record 1137; February 9, 1982
Procedure Qualification Record 1139 ; February 15, 1982
Procedure Qualification Record 1141; February 12, 1982
In-Situ Pressure Test Using the Computerized Data Acquisition System; Revision 1
WCAP 14166; Handbook of Flaw Evaluation for Prairie Island Units 1 and 2 Steam
Generators and Pressurizer; January 1995
Reactor Pressure Vessel Head and Vessel Head Penetration Nozzles
Calculation
ENG-ME-535; Effective Degradation Years for Unit 1 and 2; November 8, 2002
52
Corrective Action Documents
AR CAP 026636; Evaluate Indications Identified During RV Closure Head Bare Metal
Visual Examination; November 22, 2002
AR CAP 026603; Assess Head Temperature Used in EDY Calculation ENG-ME-535;
November 22, 2002
Engineering Work Request
EWR 003068; Inputs and Results of WCAP 14918 Should Be Verified; November 21,
2002
Drawings
NSP-521; Reactor Vessel Loops; Revision F
NSP-002; Reactor Vessel Loops; Revision E
NSP-001; Reactor Vessel Loops; Revision K
Miscellaneous Documents
Letter from Nuclear Management Corporation, LLC (NMC) to NRC; Response to NRC
Bulletin 2001-01; September 4, 2001
Letter from NMC to NRC; Response to NRC Bulletin 2001-01; March 29, 2002
Letter from NMC to NRC; 15-Day Response to NRC Bulletin 2002-01; April 3, 2002
Letter from NMC to NRC; NRC Bulletin 2002-01 60-Day Response; May 17, 2002
Letter from NMC to NRC; Supplemental Response to NRC Bulletin 2002-01;
July 19, 2002
Letter from NMC to NRC; NRC Bulletin 2002-02 15-Day Response; August 25, 2002
WO 0200959; Inspect RV Head Penetrations for Leakage; November 18, 2002
EPRI TR-1006899; Visual Examination for Leakage of PWR Reactor Head Penetrations
on Top of RPV Head; March 2002
WCAP 14918; Probabilistic Evaluation of Reactor Vessel Closure Head Penetration
Integrity for Prairie Island Units 1 and 2; July 1997
SWI GSE-23; Engineering Department Personnel Certification Program;
October 5, 2001
1R11
Licensed Operator Requalification Program
USAR 14.5.4; Steam Generator Tube Rupture; Revision 22
Procedure 1E-0; Reactor Trip or Safety Injection; Revision 21
53
NRC Inspection Report; Prairie Island Nuclear Generating Plant (PINGP) NRC
Inspection Report 50-282/01-18; 50-306/01-18; January 17, 2002
AR CAP 000232; November 2001 INPO [Institute of Nuclear Power Operations]
Evaluation; December 18, 2001
Simulator Team Evaluation PITCQ-83; Simulator Team Evaluation; September 4, 2002
1R12
Maintenance Rule Implementation
Safety-Related Cooling Water Pump Bearing/Seal Water Problems
Plant Procedure H24; PINGP Maintenance Rule Program; Revision 5
PINGP Maintenance Rule System Specific Basis Document, Cooling Water Section ;
Revision 3
PINGP Maintenance Rule Scope Determination and Performance Criteria Spreadsheet
5AWI 3.2.10; Investigation and Troubleshooting; Revision 7
5AWI 3.12.0; Nuclear Plant Maintenance; Revision 10
USAR, Section 10.4.1; Cooling Water System; Revision 22
AR CAP 023088; Unit 1 and 2 In Probabilistic Risk Assessment Orange Condition;
April 12, 2002
AR CAP 024290; Seal Water Flow on Safeguards Equipment; July 23, 2002
AR CAP 024661; 12 Diesel Driven Cooling Water Pump Declared Inoperable;
August 15, 2002
AR CAP 024872; Loss of Bearing Water Flow on 22 Diesel Driven Cooling Water Pump;
August 26, 2002
AR CAP 025866; Corrective Actions Associated with ACE 008558 Were Ineffective;
October 18, 2002
Maintenance Rule Evaluation (MRE) 000011; Evaluate High Differential Pressure on
121 Safeguards Traveling Screen; June 17, 2002
AR CAP 025920; Maintenance Preventable Functional Failure Definition for Safeguards
Traveling Screen in MRE 000011 is Not Correct; October 22, 2002
Auxiliary Building Roof Leakage
Plant Procedure H24; PINGP Maintenance Rule Program; Revision 5
PINGP Maintenance Rule System Specific Basis Document, Building Maintenance;
Revision 3
54
Volume 1C, PINGP Maintenance Rule Basis Document, Structures Monitoring Program;
Revision 2
5AWI 3.2.10; Investigation and Troubleshooting; Revision 7
5AWI 3.12.0; Nuclear Plant Maintenance; Revision 10
GEN 200202455; Water Intrusion Into TB [Terminal Box] A1265 Causing Inaccurate
Steam Release Flow; March 15, 2002
AR CAP 024598; Suspect Roof Leak Caused Water Damage to Critical Components
Internal TB-A1266; August 10, 2002
ACE 008522; Determine Roof Leakage Extent of Condition; August 14, 2002
ACE 008523; Determine If Installed Terminal Boxes and Panel That Contain Safety-
Related and/or Critical Components Are Being Properly Protected from Water Intrusion;
August 14, 2002
AR CAP 026021; No Maintenance Rule Evaluation Requested/Generated for
CAP 024598; October 29, 2002
MRE 000052; Water Damage to Critical Components of 1Z-826 Internal to TB A1266;
November 23, 2002
AR CAP 026025; Inconsistencies in Maintenance Rule Basis Documentation;
October 29, 2002
AR CAP 026063; Problems with Maintenance Rule Documentation: Consistency with
Design Basis Documents; October 31, 2002
AR CAP 027288; Auxiliary Building Roof Leakage Concerns Not Addressed in a Timely
Manner; December 18, 2002
Resolution of External Circulating Water Intake Screen Bypass Gate Repeat Failures
Unresolved Item
OTH 002196; Establish Reliability Performance Criteria for the Bypass Gates;
September 9, 2002
OTH 002199; Evaluate the Intake Screenhouse Bypass Gate Emergency Open
Solenoid Valve Reliability Against New Performance Criteria and Determine the
Maintenance Rule Status of the External Circulating Water System; September 9, 2002
Minutes of PINGP Maintenance Rule Expert Panel Meeting; November 27, 2002
1R13
Maintenance Risk Assessments and Emergent Work Control
October 16, 2002 Risk Assessment
55
Plant Status Report; October 16, 2002
Unit 2 Configuration Risk Assessment; October 16, 2002
PINGP Procedure H24.1; Assessment and Management of Risk Associated with
Maintenance Activities; Revision 5
WO 0206030; SP 2102 22 Turbine-Driven AFW Pump Monthly Test; October 16, 2002
Operating Procedure TP 1826; Outplant Safe Shutdown Equipment Check; Revision 7
October 21, 2002 Risk Assessment
Plant Status Report; October 21, 2002
Unit 2 Configuration Risk Assessment; October 21, 2002
PINGP Procedure H24.1; Assessment and Management of Risk Associated with
Maintenance Activities; Revision 5
22 Diesel Driven Cooling Water Pump Voluntary Limiting Condition of Operation Plan;
October 21, 2002
October 28, 2002 Risk Assessment
Plant Status Report; October 28, 2002
Unit 2 Configuration Risk Assessment; October 28, 2002
PINGP Procedure H24.1; Assessment and Management of Risk Associated with
Maintenance Activities; Revision 5
November 4, 2002 Risk Assessment
Plant Status Report; November 4, 2002
Unit 2 Configuration Risk Assessment; November 4, 2002
PINGP Procedure H24.1; Assessment and Management of Risk Associated with
Maintenance Activities; Revision 5
AR CAP 026066; Operations and Schedule Department-Level Implementing Procedures
Do Not Exist for Maintenance Rule (a)(4) (H24.1); October 31, 2002
1R14
Nonroutine Evolutions
Response to a Seismic Alarm Received Following Alaskan Earthquake
Abnormal Operating Procedure, AB-3; Earthquakes; Revision 18
56
Emergency Plan Implementing Procedure F3-2; Classification of Emergencies;
Revision 30
Technical Requirements Manual, Section 3.3.4; Miscellaneous Instrumentation;
Revision 3
Operations Logs, Control Room; November 3 through November 4, 2002
Alarm Response Procedure 47023-0603; Seismic Event; Revision 23
Remote Alarm Response Procedure C81000; Seismic Event; Revision 0
5AWI 8.2.4; Shelf Life Program; Revision 0
AR CAP 026100; Seismic Equipment, Unable to Read Chart; November 3, 2002
AR CAP 026101; Delay In Confirming Magnitude of Seismic Activity; November 3, 2002
AR CAP 027235; Evaluate and/or Determine Maintenance Department Shelf Life
Controls; December 13, 2002
CE 001350; Evaluate and If Necessary Initiate Corrective Action Regarding
CAP 026201; November 7, 2002
OPR 000350; Operability of Seismic Monitor Chart Recorder as Used In AB-3;
November 4, 2002
AR CAP 027232; Improved Guidance Needed in F3-2 Regarding Classification of
Earthquakes; December 13, 2002
AR CAP 027233; Improved Guidance Needed in AB-3 Earthquakes;
December 13, 2002
CA 003539; Evaluate and If Necessary Initiate Corrective Action Regarding
CAP 027232; December 17, 2002
CA 003540; Evaluate and If Necessary Initiate Corrective Action Regarding
CAP 027233; December 17, 2002
PINGP 1224; Crew Meeting Review of Noteworthy Event/Near Miss/Change;
November 8, 2002
SWI EP-300; Emergency Plan Activation Evaluation; Revision 0
OTH 023756; Using Guidance of SWI EP-300, Emergency Plan Activation Evaluation,
Relative to the November 3, 2002, Seismic Annunciator Alarm Event; January 9, 2003
Unit Shutdown and Cooldown
Operating Procedure 1C1.3; Unit 1 Shutdown; Revision 50
57
Operating Procedure 1C15; Residual Heat Removal System Unit 1; Revision 25
Operating Procedure 1C28.1; Auxiliary Feedwater System Unit 1; Revision 7
Emergency Operating Procedure 1ES-0.1; Reactor Trip Recovery; Revision 20
AR CAP 026338; Unit 1 Manual Reactor Trip from 12 percent Power Due to 13A
Feedwater Heater Level Problems; November 16, 2002
AR CAP 026333; 11 TDAFW [Turbine Driven Auxiliary Feedwater] Pump Auto Start Due
to Less Than Adequate Guidance in 1ES-0.1; November 16, 2002
ACE 008608; Evaluate Response and Followup to Unit 1 Manual Reactor Trip Event on
11/15/2002; December 4, 2002
AR CAP 027157; Equipment Not Quarantined Following Reactor Trip on 11/15/2002;
December 10, 2002
AR CAP 026346; Procedure C15 Has RHR Heat Exchanger Flow of 2600-2800,
Checklist C1.14 Has 2500; November 16, 2002
RCS Draindown
Integrated Checklist D2-1; Draining the Reactor Coolant System - Unit 1; Revision 24
Special Operations Procedure 1D2.1; RCS Reduced Inventory Operation After Pool
Flood; Revision 15
AR CAP 026447; RCS Level Indication Discrepancies During RCS Draindown to Top of
Hot Leg; November 19, 2002
Reactor Vessel Head Removal
WO 0114534; Unit 1 Reactor Vessel Head Removal; November 20, 2002
Maintenance Procedure D58.1.9; Unit 1- Reactor Vessel Head Removal; Revision 7
Reduced Inventory Operation
PINGP 1102; Unit 1 Shutdown Safety Assessment for Vessel Level 1 Foot Below Vessel
Flange; Revision 19
Operating Procedure 1C4.2; RCS Inventory Control - Post Refueling; Revision 12
Operating Procedure 1D2; RCS Reduced Inventory Operation; Revision 13
Unit Startup
Operating Procedure 1C1.2; Unit 1 Startup Procedure; Revision 29
Abnormal Operating Procedure 1C5 AOP3; Misalignment of Groups Within a Bank;
Revision 6
58
1R15
Operability Evaluations
Post-Loss-of-Coolant Accident (LOCA) Containment Integrity Analysis Peak
Containment Temperature
USAR 6.3.1.1; Containment Heat Removal Systems; Revision 22
5AWI 16.0.0; Action Request Process; Revision 1
AR CAP 025493; Peak Containment Temperature During LOCA; September 30, 2002
Memorandum, NAD File OC.PX.01.011; Updated Containment Pressure and
Temperature Response Following a Large Break LOCA; March 6, 2001
1R16
SI Pump Venting
TS 3.5.2 and Bases; Emergency Core Cooling Systems - Operating; Revision 4
USAR 6.2; Safety Injection System; Amendment 158
Operator Workarounds; Venting of SI Pumps to Mitigate Possible Gas Intrusion;
October 30, 2002
AR CAP 023477; Free Climbing on 11 SI Pump to Operate Valve PT-17110;
May 13, 2002
WO 0206718, 0206719, 0206720, and 0206721; Install J-Hook Fitting for SI Pump
Venting; August 6, 2002
5AWI 3.10.8; Equipment Problem Resolution Process; Revision 1
Plant Status Report; November 6, 2002
Operating Procedure C11; Radiation Monitoring System; Revision 25
Cumulative Effects of OWAs
5AWI 3.10.8; Equipment Problem Resolution Process; Revision 1
PINGP List of Operator Workarounds for Unit 1 and Unit 2; December 10, 2002
Operator Workaround Aggregate Impact Analysis, Third Quarter 2002;
November 6, 2002
1R17
Permanent Plant Modifications
TS 3.7.8; Cooling Water System; Revision 131
USAR 10.4.1; Cooling Water System; Revision 22
WO 0204494; Tie In Additional Bearing Water Supply Piping to 22 Cooling Water Pump
59
Design Change 02CL01; Bearing Water to Cooling Water Pumps Modification;
Revision 0
10 CFR 50.59 Evaluation; Bearing Water to Cooling Water Pumps Modification 02CL01;
Revision 0
DBD SYS-35; Cooling Water System; Revision 4W
1R19
Post-Maintenance Testing
124 Air Compressor
WO 0206295; P3505-1-124 124 Air Compressor 1000 Hour PM; October 14, 2002
High Risk Maintenance Activities for the Work Week of October 14, 2002 (2403B);
October 14, 2002
AR CAP 025841; 124 Air Compressor Cooling Jacket Full of Mud; October 17, 2002
22 Diesel-Driven Cooling Water Pump
WO 025889; SP 1106B 22 Diesel Cooling Water Pump Monthly Test; October 26, 2002
AR CAP 025986; Missed Forced Cascade During 22 DDCL Pump Outage;
October 26, 2002
AR CAP 026010; Loose Oil Absorbent Materials Were Found in 22 DDCL Pump Room;
October 28, 2002
AR CAP 022335; Oil Absorbent Pads and a Snake Were Found in 12 and 22 DDCL
Pump Rooms; January 9, 2002
11 Safety Injection Pump
WO 0114563; PM 3117-1-11 11 SI Pump Inspection; November 6, 2002
Preventive Maintenance Procedure PM 3117-1-11; 11 Safety Injection Pump Refueling
Inspection; Revisions 8 and 9
22 Diesel-Driven Cooling Water Pump
WO 0204494; Tie In Additional Bearing Water Supply to 22 CL Pump;
November 11, 2002
SP 1106B; 22 Diesel Cooling Water Pump Monthly Test; Revision 59
22 Diesel-Driven Cooling Water Pump
WO 0211272; Restore Valve 2CL-136-1 for Bearing Water 22 DDCL Pump;
December 16, 2002
AR CAP 027261; 22 Diesel Cooling Water Pump Governor; December 17, 2002
1R20
Refueling and Other Outage Activities
60
5AWI 15.6.1; Shutdown Safety Assessment; Revision 1
PINGP 1102, Unit 1 Shutdown Safety Assessment; Unit 1 Shutdown Safety
Assessments; November 16, 2002 through November 29, 2002
Special Operations Procedure D5.2; Reactor Refueling Operations; Revision 34
AR CAP 026639; Four Inch Lockwire Potentially Dropped Into Innermast of Manipulator
Crane During Maintenance; November 23, 2002
AR CAP 027260; Evaluation/Action Not Initiated Following Screening of CAP 026366;
December 16, 2002
1R22
Surveillance Testing
SP 1392, Unit 1 RCS Bolting Inspection
WO 0200136; Unit 1 RCS Bolting Inspection; November 16, 2002
SP 1392; Unit 1 RCS Bolting Inspection; Revision 1
Plant Procedure H2; Program for Identification and Disposition of Small Reactor Coolant
Leakage on Low Alloy Reactor Coolant Pressure Boundary Components; Revision 3
SP 1083, Unit 1 Integrated SI Test With a Simulated Loss of Offsite Power
WO 0114254; Integrated SI Test with Simulated Loss of Offsite Power;
November 16, 2002
SP 1083; Unit 1 Integrated SI Test With a Simulated Loss of Offsite Power; Revision 27
AR CAP 026425; Continuous Use Procedure Compliance Issues During SP 1083
(Integrated SI); November 18, 2002
SP 1092B, Safety Injection Check Valve Test Part B
WO 0114257; SI Check Valve Test (Head Off) Part B: RWST; November 20, 2002
Surveillance Procedure P 1092B; Safety Injection Check Valve Test (Head Off) Part B:
RWST to RHR Flow Path Verification; Revision 10
SP 1092A, Safety Injection Check Valve Test Part A
WO 0114256; SI Check Valve Test Reactor Vessel Head Off Part A;
November 20, 2002
SP 1092A; SI Check Valve Test (Head Off) Part A: High Head SI Flow Path
Verification; Revision 22
SP 1177, Core Inventory Verification
61
WO 0114283; Core Inventory Verification; November 25, 2002
SP 1177; Core Inventory Verification; Revision 9
Core Operating Limits Report - Unit 1, Cycle 22; Revision 0
Core Operating Limits Report - Unit 1, Cycle 21; Revision 2
SP 1305, D2 Diesel Generator Monthly Slow Start Test, and SP 1335, D2 Diesel
Generator 18-Month 24-Hour Load Test
WO 0207269; D2 Diesel Generator Monthly Slow Start Test; November 25, 2002
SP 1305; D2 Diesel Generator Monthly Slow Start Test; Revision 28
WO 0209430; D2 Diesel Generator 18-Month 24-Hour Load Test; November 25, 2002
SP 1335; D2 Diesel Generator 18-Month 24-Hour Load Test; Revision 8
TS 3.8.1 and 3.8.2; AC Sources - Operating; and AC Sources - Shutdown; Amendment
No. 158
SP 1008, Reactor Protection Logic Time Response Test
WO 0114190; Reactor Protection Logic Time Response Test; November 14, 2002
SP 1008; Reactor Protection Logic Time Response Test; Revision 23
SP 1092D, Safety Injection Check Valve Test
WO 0114259; SI Check Valve Test Reactor Vessel Head On Part D: Low Head;
December 2, 2002
SP 1092D; Safety Injection Check Valve Test (Head On) Part D: Low Head SI
Discharge Flow Path Verification; Revision 3
WO 0114268; Turbine Building Cooling Water Header Isolation SI Relay Test;
December 2, 2002
SP 1126; Turbine Building Cooling Water Header Isolation SI Relays 1SI-12X and
1SI-22X Contact Verification Test; Revision 4
SP 1834, Unit 1 Containment Coating Inspection
WO 0115305; Unit 1 Containment Coating Inspection; November 24, 2002
SP 1834; Unit 1 Containment Coating Inspection; Revision 0
SP 1070, Reactor Coolant System Integrity Test
62
WO 0114211; Reactor Coolant System Integrity Test; December 3, 2002
SP 1070; Reactor Coolant System Integrity Test; Revision 33
AR CAP 027049; Excess Letdown Heat Exchanger Endbell Flange Leak During
SP 1070; December 5, 2002
SP 1750, Post Outage Containment Close-Out Inspection
WO 0114186; Post Outage Containment Close-Out Inspection; November 29, 2002
SP 1750; Post Outage Containment Close-Out Inspection; Revision 25
1R23
Cooling Water Pipe Patch
Temporary Modification 02T131; Containment Cooling Line 14-ZX-6 Pipe Patch;
May 10, 2002
NMC Standard 10 CFR 50.59 Screening 1487; Revision 0
AR CAP 024556; ZX [Containment Cooling] Piping Inclusion On Top Ten Equipment
List; August 8, 2002
AR CAP 021192; Leak on Chill Water Line 14-ZX-6, the Common Header to Unit 1 and
Unit 2 ; March 27, 2002
CA001896; Perform Action Plan for ZX Piping to Increase Reliability; August 10, 2002
Construction Code B 31.1; 1969
Prairie Island USAR, Section 5.2.2.3.1; Containment Air Cooling Systems; Revision 22
Instrument Air Pipe Clamp
Temporary Modification 02T147; Instrument Air Pipe Clamp
NMC Standard 10 CFR 50.59 Screening 1632; Revision 0
Operations Logs; 10/22/02, 9:18 P.M.
5AWI 6.5.0; Temporary Modifications; Revision 11
DBD SYS-34; Design Basis Document - Station and Instrument Air System;
Revision 4W
Prairie Island USAR, Section 10.3.10.2.2; Instrument Air System; Revision 23
1EP6
Drill Evaluation
PINGP Emergency Plan Drill Package; October 23, 2002, Revision 0
63
PINGP Emergency Plan Drill Critique Report; October 23, 2002
AR CAP 025951; 2002 Fall Drill - Dosimeters Were Not Distributed to Security;
October 24, 2002
AR CAP 0025952; 2002 Fall Drill - Plant Evacuation Ordered in an Untimely Manner;
October 24, 2002
AR CAP 0025955; 2002 Fall Drill - Provide an Evacuation Switch in the Technical
Support Center; October 24, 2002
AR CAP 0025956; Establish Fast-Track Dispatch for Duty Operators from Operational
Support Center; October 24, 2002
AR CAP 0025957; 2002 Fall Drill - Cross-Tie of 480-Volt Safeguards Buses Considered
Untimely; October 24, 2002
2OS1 Access Controls for Radiologically Significant Areas
Radiation Protection Implementing Procedure (RPIP) 1133; Multiple TLD
[Thermoluminescent Luminescent Dosimeter] Badging; Revision 8
RPIP 1135; RWP [Radiation Work Permit] Coverage; Revision 13
AR CAP 023388; Radiological Postings Removed; May 6, 2002
AR CAP 023386; Contamination Found in a Clean Area Around U2 RHR Pits; May 6,
2002
AR CAP 023404; Operator Reached Across a Rad Boundary and Operated a Valve with
Bare Hands; May 7, 2002
AR CAP 026493; High Radiation Area Boundary Left Down; November 20, 2002
AR CAP 023449; Neutron Posting Left Down; May 9, 2002
AR CAP 023459; Roll-up of Rad Worker Practices Issues for the Week Ending 5/9/02;
May 10, 2002
AR CAP 023478; Operator Received a Dose Alarm While in the RHR Pit; May 13, 2002
AR CAP 023566; Worker Received Dose Alarm During Spent Fuel Pool Skimmer Filter
Change-out; May 20, 2002
64
AR CAP 023912; Barrel Yard RCA Boundary Was Left Down and Unattended; June 20,
2002
AR CAP 023914; Worker Exhibiting Poor Rad Practices; June 20, 2002
AR CAP 023930; Snubber Test Stand Found to be Contaminated During Routine
Survey; June 21, 2002
AR CAP 023974; Contaminated Area Incorrectly Posted; June 25, 2002
AR CAP 024061; Locked HRA Sign Was Found Laying on the Floor Near Locked HRA;
July 3, 2002
AR CAP 024220; Radiologically Controlled Areas Have Dual Postings; July 18, 2002
AR CAP 024286; Green Drain Hose Internally Contaminated; July 22, 2002
AR CAP 025715; Rad Worker Practice Changes Not Adequately Conveyed to Plant
Personnel; October 11, 2002
AR CAP 025915; Painter Received a Dose Alarm on His ED [Electronic Dosimeter]
While in ISFSI [Independent Spent Fuel Storage Installation]; October 22, 2002
AR CAP 026095; Individual Left RCA Prior to Clear Friskall; November 2, 2002
AR CAP 02339; Worker Sweeping from Inside Contaminated Area to Outside the Area;
November 16, 2002
AR CAP 026493; High Radiation Area Boundary Left Down; November 20, 2002
2OS2 ALARA Planning and Controls
SA 021671; Radiation Protection Self Assessment; September 13, 2002
D27.18; Special Operations Procedure - Stem Generator Nozzle Dam Installation;
Revision 22
MSIP 7009; Steam Generator Nozzle Dam Installation Pre-job Briefing
RPIP 1004; Radiation Protection ALARA Program; Revision 5
5AWI 10.1.1; ALARA Plan; Revision 0
RWP 1022; ALARA Review 2002 U1 SG Primary Manway Remove and Install;
October 8, 2002
RWP 1027; ALARA Review 2002 U1 SG Primary Nozzle Dam Install and Remove and
SG Closeout Inspection; October 14, 2002
65
PINGP 1112; Pre-job Brief - 12 CL Insert and Hot Particle Removal; November 19, 2002
AR CAP 023227; Investigate Potential Negative Trend in Entering Controlled Area
Without Electronic Dosimetry; April 22,2002
AR CAP 023724; Maintenance Working in Contaminated Area After Hours with No HP
[Health Physics] Support; June 6, 2002
AR CAP 023725; U2 CS Pump Room Scaffold Added to Work Week Without Informing
ALARA Contact; June 6, 2002
AR CAP 023992; Emergency Electronic Dosimeter Alarm Set-points Were Not Reset
Before Issue; June 26, 2002
AR CAP 024129; Operators Performed SP 2090A Under Wrong RWP; July 12, 2002
AR CAP 024140; Clean Area in U2 CS Pump Room Was Contaminated While
Performing SP 2090A; July 12, 2002
AR CAP 025131; WO 200241 is for Work in Containment and RWP Required Block
Was N; September 10, 2002
AR CAP 025490; Dose Goal Not Met 9/22 to 9/29/02; September 30, 2002
AR CAP 026489; Outage Delay and Extra Dose Due to Discreet Radioactive Particle on
12 S/G Cold Leg Diaphragm; November 20, 2002
4OA1 Performance Indicator Verification
Reactor Coolant System Leakage
TS 3.1.8; Reactor Coolant System Leakage; Revision 91
Operations Log Entries, Units 1 and 2; August 1, 2001, through September 1, 2002
AR CAP 025257; Potentially Incorrect Primary to Secondary Leak Rate Values;
September 17, 2002
SP 1001AA; Daily Reactor Coolant System Leakage Test; Revision 30
WO 0205837; SP 1001AA Daily Reactor Coolant System Leakage Test; October 10,
2002
Safety System Unavailability - Emergency AC Power System
Performance Indicator Data Summary Reports; Safety System Unavailability -
Emergency AC Power System; 4th Quarter 2001, 1st Quarter 2002, 2nd Quarter 2002,
and 3rd Quarter 2002
Operations Log Entries; Unit 1 and Unit 2 Control Room; October 1, 2001, through
October 24, 2002
66
SP 2093; D5 Diesel Generator Monthly Slow Start Test; Revision 71
SP 2305; D6 Diesel Generator Monthly Slow Start Test; Revision 19
AR CAP 024181; Radiation Area Sign Was Found Laying on the 695 Drop Area Floor;
July 16, 2002
AR CAP 025662; Radiation Area Sign Found Down; October 8, 2002
AR CAP 026004; Potential Adverse Trend in Rad Worker Practices; October 28, 2002
AR CAP 026093; High Radiation Area Key Locker Was Found Open and Unguarded at
Access; November 2, 2002
4OA2 Identification and Resolution of Problems
Letter From Walter Djordjevic To Mark McKeown; Walkdown Assessment of D1/D2
[Emergency Diesel Generators] Tornado Missile Vulnerability; September 10, 2002
GEN-PI-005; Tornado and Seismic Evaluation of D1 and D2 Components; Revision 0
ENG-CS-233; Tornado Missile Evaluation; Revision 0
ANSI/ANS-2.3-1983; Standard for Estimating Tornado and Extreme Wind
Characteristics at Nuclear Power Sites; American Nuclear Society, 1983
USAR Table 12.2-1; Classification of Structure, Systems, and Components; Revision 23
DBD TOP-05; Hazards; Revision 2W
DBD STR-03; Turbine Building; Revision 2W
GEN 20014805; Inadequate D1/D2 Diesel Tornado Damage Analysis; June 7, 2001
AR CAP 000137; Inadequate D1/D2 Diesel Tornado Damage Analysis; June 4, 2001
OPR 000054; Operability Recommendation CAP 000137
4OA3 Event Followup
Response to a Seismic Alarm Received Following Alaskan Earthquake
Abnormal Operating Procedure, AB-3; Earthquakes; Revision 18
Emergency Plan Implementing Procedure F3-2; Classification of Emergencies;
Revision 30
Technical Requirements Manual, Section 3.3.4; Miscellaneous Instrumentation; Revision
3
67
Operations Logs, Control Room; November 3 through November 4, 2002
Alarm Response Procedure 47023-0603; Seismic Event; Revision 23
Remote Alarm Response Procedure C81000; Seismic Event; Revision 0
5AWI 8.2.4; Shelf Life Program; Revision 0
AR CAP 026100; Seismic Equipment, Unable to Read Chart; November 3, 2002
AR CAP 026101; Delay In Confirming Magnitude of Seismic Activity; November 3, 2002
AR CAP 027235; Evaluate and/or Determine Maintenance Department Shelf Life
Controls; December 13, 2002
CE 001350; Evaluate and If Necessary Initiate Corrective Action Regarding CAP
026201; November 7, 2002
OPR 000350; Operability of Seismic Monitor Chart Recorder as Used In AB-3;
November 4, 2002
AR CAP 027232; Improved Guidance Needed In F3-2 Regarding Classification of
Earthquakes; December 13, 2002
AR CAP 027233; Improved Guidance Needed In AB-3 Earthquakes;
December 13, 2002
CA 003539; Evaluate and If Necessary Initiate Corrective Action Regarding
CAP 027232; December 17, 2002
CA 003540; Evaluate and If Necessary Initiate Corrective Action Regarding
CAP 027233; December 17, 2002
PINGP 1224; Crew Meeting Review of Noteworthy Event/Near Miss/Change;
November 8, 2002
SWI EP-300; Emergency Plan Activation Evaluation; Revision 0
OTH 023756; Using Guidance of SWI EP-300, Emergency Plan Activation Evaluation,
Relative to the November 3, 2002, Seismic Annunciator Alarm Event; January 9, 2003
EPPOS No. 2; Emergency Preparedness Position On Timeliness Of Classification Of
Emergency Conditions, Revision 0
NEI 99-02, Section 2.4; Emergency Preparedness Cornerstone; Revision 2
4OA5 Other Activities
TI 2515/149; Mitigating Systems Performance Index Pilot Verification; September 24,
2002
68
Draft NEI 99-02 MSPI, Appendix F; Methodologies for Computing the Unavailability
Index and Determining Performance Index Validity; Revision 0
Draft NEI 99-02 MSPI, Attachment A; Mitigating System Performance Index;
September 24, 2002
Electronic Control Room Logs; July 1, 2000, through September 30, 2002
Electronic Limiting Conditions for Operations Logs; July 1, 2000, through September 30,
2002
Excel Spreadsheets for MSPI Data Submittals, Baseline Data; 2nd Quarter 2002, and 3rd
Quarter 2002
Performance Indicator Data; from www.nrc.gov/NRR/OVERSIGHT/ website; 3rd Quarter
2000 through 3rd Quarter 2002
Prairie Island MSPI Notebook
4OA7 Licensee-Identified Violation
PINGP TS, Section 3.7.8; Cooling Water System; Amendment 158
PINGP TSs, Section 3.7.8; AC Sources; Amendment 158
AR CAP 025986; Missed Forced Cascade During 22 DDCL Pump Outage; October 26,
2002
CE 001282; Evaluate Potential Reportability of Failure to Complete SP 1118;
October 29, 2002
Root Cause Evaluation 000175; Perform Root Cause Evaluation into 22 DDCL Pump
Issue; October 29, 2002
Operator Logs from October 24 through October 26, 2002
SP 1118; Verifying Paths from the Grid to Unit 1 Buses; Revision 15
DBD SYS-15; Design Basis Document for the Residual Heat Removal System;
Revision 3
1C1.3; Unit 1 Shutdown Procedure; Revision 50
USAR Section 4.4.3.3; Low Temperature Overpressurization Mitigation; Revision 23
USAR Section 6.2; Safety Injection System; Revision 22
TS 3.4.12; Low Temperature Overpressure Protection; Amendment 158
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TS 3.4.13; Low Temperature Overpressure Protection; Amendment 158
AR CAP 026440; Discovered Test Rod Installed on RH-8-1, 11/12 RHR Pumps Suction;
November 18, 2002
ACE 008610; Conduct ACE Regarding CAP 026440; November 20, 2002
OPR 000358; Determine if Valve/RHR is Operable in This Configuration; November 19,
2002
LIST OF ACRONYMS USED
Alternating Current
Apparent Cause Evaluation
Agencywide Documents Access and Management System
As-Low-As-Is-Reasonably-Achievable
Action Request
American Society of Mechanical Engineers
AWI
Administrative Work Instruction
B
CA
Caustic Addition
Corrective Action Program
Component Cooling Water
Condition Evaluation
CL
Cooling Water
CFR
Code of Federal Regulations
Design Basis Document
DDCL
Diesel-Driven Cooling Water
F
Degrees Fahrenheit
Division of Reactor Projects
Electronic Dosimeter
EDY
Effective Degradation Years
EPPOS
Emergency Preparedness Position
Eddy Current
Engineering Work Request
GEN
General Condition Report
Gas Tungsten Arc Welding
HC
Hydrogen Control
Health Physics
Homeland Security Advisory System
Initiating Event
IMC
Inspection Manual Chapter
Institute of Nuclear Power Operations
Individual Plant Examination of External Events
70
IR
Inspection Report
Independent Spent Fuel Storage Installation
Inservice Inspection
Loss of Coolant Accident
Motor Control Center
MDCL
Motor-Driven Cooling Water
Maintenance Rule Evaluation
MS
Mitigating System
Maintenance Standards Implementing Procedure
Mitigating Systems Performance Index
Non-Cited Violation
NEI
Nuclear Energy Institute
Nuclear Management Corporation, LLC
NRC
U.S. Nuclear Regulatory Commission
Northern States Power
OTH
Other
OPR
Operability Recommendation
Operator Workaround
Publicly Available Records
Prairie Island Nuclear Generating Plant
Preventive Maintenance
Post-Maintenance Test
Dye Penetrant
Pressurized Water Reactor
RC
Radiologically Controlled Area
Regulatory Information Summary
RPIP
Radiation Protection Implementing Procedure
RV
Reactor Vessel
Radiation Work Permit
Refueling Water Storage Tank
Significance Determination Process
Safety Injection
Surveillance Procedure
SR
Surveillance Requirement
Terminal Box
Turbine-Driven Auxiliary Feedwater
TI
Temporary Instruction
Thermoluminescent Dosimeter
TS
Technical Specification
Unresolved Item
Updated Safety Analysis Report
Ultrasonic
VHP
Vessel Head Penetration
Very High Radiation Area
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Work Order
ZX
Containment Cooling
72
December 20, 2002
MEMORANDUM TO: John Thompson, Senior Reactor Operations Engineer
Inspection Programs Branch
Division of Inspection Program Management
Office of Nuclear Reactor Regulation
THRU:
Ken Riemer, Branch Chief
Reactor Programs Branch 5, Region III
FROM:
John Adams, Senior Resident Inspector, Prairie Island
SUBJECT:
COMPLETION OF TEMPORARY INSTRUCTION (TI) 2515/149 AT
PRAIRIE ISLAND
The inspectors completed the requirements of TI 2515/149, Mitigating Systems Performance
Index (MSPI) Pilot Verification, at Prairie Island on December 20, 2002. The inspectors
determined that the licensee made a reasonable best effort to provide accurate and complete
data for this voluntary pilot program. Most data errors were small and most other problems
were because the guidance for the MSPI program was still under development.
The following discrepancies/issues were noted: (Paragraph numbers correspond to the
inspection requirements sections of TI 2515/149.)
03.02 Risk-Significant Functions
The licensee did not originally specify which Maintenance Rule risk-significant
functions were to be counted as MSPI functions. All Maintenance Rule functions
were listed. Licensee engineers revised the list of functions during the
inspection.
The licensee originally listed the auxiliary feedwater (AFW) system function as
To provide water to the steam generators ... Since the success criterion is met
by only supplying flow to one steam generator, the function should have been
stated as To provide water to at least one steam generator ... to be consistent
with Nuclear Energy Institute (NEI) 99-02, draft Attachment A. Licensee
engineers corrected the function description during the inspection.
The licensee did not include the electrical cross-ties from the other units
safeguards busses as a risk-significant function of the emergency AC power
(EAC) system although it is modeled in its probabilistic risk assessment (PRA)
and is a significant factor in calculating the Fussell-Vesley (F-V) value. (See
additional comments under 03.04.)
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03.03 Success Criteria
The licensees MSPI and Maintenance Rule success criteria for AFW included
providing 200 gallons per minute (gpm) to at least one steam generator within
one minute at 1300 pounds per square inch - atmosphere (psia). The licensees
design basis documentation (DBD) stated success is 200 gpm to at least one
steam generator within one minute at 1142.6 pounds per square inch - gauge
(psig). Licensee engineers revised the MSPI success criteria to match the
design basis of 1142.6 psig during the inspection.
The licensees MSPI success criteria did not indicate where the parameters
specified came from (such as DBD, Updated Safety Analysis Report (USAR), or
PRA). The licensee was informed that this information should be available for
inspection.
One of the success criteria for the component cooling water (CC) system was
listed as 200 degrees. This was a piping design limit but obviously the system
could not meet its function of cooling front line systems if it were that hot. The
licensee was informed that this criterion should be revised.
03.04 Unreliability Boundary Definition
For AFW, the licensee did not document why the valves in the safety-related
backup water supply from the cooling water system were not included as active
components.
The licensee did not document why AFW steam generator isolation valves ( such
as MV-32242) are not considered active components like they did for the throttle
valves (such as MV-32238).
For AFW, the licensee included the recirculation valves (CV-31153, CV-31154,
CV-31418, and CV-31419) as active components but they have no F-V because
they are not modeled in the PRA. There was a statement in the licensees MSPI
documentation that the valves will be modified to be normally open, but that is
not true anymore. Since the valves have no F-V values, unreliability data
submitted for these valves do not get counted in the MSPI calculation.
For the cooling water (CL) system, the licensee did not document why dump-to-
grade valves MV-32329, 32322, and 32036 were not included as active
components.
For CC, the licensee included MV-32120 and other valves as active components
but they had zero F-V values assigned. The licensee documented a qualitative
discussion as to why the F-V valves would be negligible, but did not provide any
quantitative evaluation to support it. The licensee stated that the valves were
modeled in the PRA and that they would provide the quantitative importance
values. Since the valves have such low F-V values, their unreliability data do not
contribute to the MSPI calculation.
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For CL, the heat exchanger throttle valves (CV-31381, CV-31411, CV-31383,
and CV-31384) are included as active components but are not modeled in the
PRA and have F-V values of zero. Therefore, unreliability data reported for
these valves do not get counted in the MSPI calculation.
Emergency Operating Procedure E-0, Step 8, has an action to close MV-32115,
Component Cooling Water Supply to the Spent Fuel Pool Heat Exchanger.
The USAR indicates that a component cooling train could fail due to excessive
flow if the valve is not closed. The licensee did not include this valve as an
active component but agreed during the inspection that it should be included.
For EAC, the cross-tie breakers from the other unit are modeled in the PRA and
have a large effect on the F-V values for the emergency diesel generators.
However, the licensee did not include the cross-tie breakers as active
components. According to NEI 99-02, the breakers should be included as active
components since they are in the PRA. Licensee engineers stated during the
inspection that they intend to add the breakers as active components. However,
NEI 99-02, Draft Appendix F, Table 2, does not have industry information for
breakers, and they are not listed as one of the component types to choose from
in the MSPI spreadsheet. In order to add these active components, the NEI
spreadsheet will have to be revised.
The licensee did not document why the safety injection accumulator discharge
valves were not included as active components although the Emergency
Operating Procedures direct that they be closed during certain accidents.
For the high pressure safety injection (SI) system, valves, such as MV-32202,
were included as active components but are not in the PRA. F-V values were
assigned that the licensee PRA engineers say are conservative, but they did not
make similar assignments for other valves without F-V values. The licensee
should justify why number is conservative, and possibly apply the same
technique to other valves like CV-31381 discussed above. During the
inspection, the licensee stated that they will consider assigning conservative F-V
values to all active components not modeled in the PRA.
The licensees PRA model assumed the A train CC pump and both non-safety
CL pumps were continuously running. Since the model assumed they were
running, there was no unavailability F-V importance factor for them. Thus any
unavailability data for those pumps do not get counted in the MSPI calculation.
However, the licensee reported unavailability hours for those pumps.
Unavailablity hours for the pumps assumed to be running in the PRA should be
assigned to the pumps assumed to be in standby so that they get counted in the
MSPI calculation, or appropriate unavailability F-V values should be assigned to
the pumps. The licensees PRA engineer stated that this issue would be
reviewed.
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03.05 Train/Segment Unavailability Boundary Definition
The licensee did not specify electrical boundaries. NEI 00-02 guidance stated
that the last breaker or relay for electrical power and controls should be in the
boundaries for pumps and valves.
03.06 Entry of Baseline Data - Planned Unavailability
The licensees calculation for subtracting unplanned unavailability from total
unavailability to get just the planned hours had a discrepancy in that some
cascading unplanned unavailability hours were more than the total unplanned
unavailability hours for the train. This resulted in errors in the baseline planned
unavailability. Licensee engineers found the source of the error during the
inspection.
03.07 Entry of Baseline Data - Unplanned Unavailability
No discrepancies were noted. Correct table values were used.
03.08 Entry of Base line Data - Unreliability
No discrepancies were noted. Correct table values were used.
03.09 Entry of Performance Data - Unavailability
The inspectors sampled data reported for the 2nd quarter 2002 for CC and CL
and the 3rd quarter 2002 for AFW for the current performance index and also
sampled data for the 3rd quarter 2000 for AFW and 4th quarter 2000 for CC and
CL for verification of historic values.
No discrepancies were identified in AFW unavailability data for the 3rd quarter
2002.
The licensee made a small error in the reported unavailable time for the 22 CC
train when there was a problem with the 22 CC heat exchanger temperature
control valve, CV-31384, on May 5-6, 2002. Licensee engineers found the
source of the error during the inspection.
No discrepancies were noted in the CL unavailability for the 2nd quarter 2002.
The inspectors identified errors in the reported data for unavailability of AFW for
the 3rd quarter 2000 for all except the 12 AFW pump. Licensee engineers later
identified that some unavailable time had been double counted.
03.10 Entry of Performance Data - Unreliability
The inspectors sampled data from the 2nd quarter 2002 for CC and CL and the 3rd
quarter 2002 for AFW for current performance and also sampled data for the 3rd quarter
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2000 for AFW and 4th quarter 2000 for CC and CL for verification of historic values. The
inspectors also performed a very limited sampling of data for other systems.
For the AFW, SI, and RHR systems, the licensee estimated pump start
demands, run times, and valve stroke demands based on normal surveillance
schedules. The licensee did not provide auditable records of how those
estimated were obtained.
The inspectors noted that the licensee reported one start demand for each RHR
pump during the 2nd quarter 2002. According to the electronic control room log
and process book, there were two demands on the 22 RHR pump. This was one
example of an error due to estimating start demands and run times based only
on the number of surveillance tests that are typically done.
The licensee reported the correct number of start demands for the 11 and 12 CC
pumps for the 2nd quarter 2002. However, the inspectors identified that one of
the starts on each of the pumps was a post-maintenance test (PMT). In general,
the licensee did not eliminate PMTs from reported start demands for most
systems.
The inspectors identified that the run hours reported for the 11 CC pump were
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> short for the 2nd quarter 2002. Licensee engineers found the source of
the error during the inspection.
The licensee reported seven starts for each of the 21 and 22 CC pumps in the
2nd quarter 2002. However, the inspectors determined that one of the starts on
the 21 CC and two of the starts on the 22 CC were PMTs and should not have
been counted.
The inspectors identified that the licensee did not report the May 2, 2002, trip of
the 22 CL pump as a start demand failure (it was running less than an hour).
The trip was due to a spurious overspeed trip due to radio interference. The trip
happened during a surveillance test but took more than a trivial amount of time
to diagnose. The inspectors determined that the trip should have been
considered a start demand failure. During the inspection, the licensee agreed to
count it as a failure.
The licensee reported six start demands on the 22 CL pump during the 3rd
quarter 2002. The inspectors could only identify four. During the inspection, the
licensee found the source of the error.
03.11 MSPI Calculation
Some of the MSPI F-V coefficients were not verified because the licensee had
not identified all of the F-V coefficients due to certain components not being
modeled in their PRA (as noted in Section 03.04) or the F-V coefficient was
truncated out at a 1E-10 value. Specific components with no F-V value due to
truncation include:
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Units 1 and 2 CC heat exchanger outlet valves, MV-32120, MV-32121,
MV-32122, and MV-32123;
Units 1 and 2 Turbine Building Loop A/B Cooling Water Header Valves,
MV-32031 and MV-32033;
Units 1 and 2 SI pump suction valves, MV-32163 and MV-32191;
Units 1 and 2 SI test to refueling water storage tank isolation valves,
MV-32202, MV-32203, MV-32204, and MV-32205;
Units 1 and 2 Bus 15 to Bus 25 tie breaker, 15-8; and
Units 1 and 2 Bus 25 to Bus 15 tie breaker, 25-17.
The NRC staff has not qualified the licensees PRA.