ML050460220
| ML050460220 | |
| Person / Time | |
|---|---|
| Site: | Kewaunee  |
| Issue date: | 02/14/2005 |
| From: | Kozak T Division Reactor Projects III |
| To: | Lambert C Nuclear Management Co |
| References | |
| IR-04-009 | |
| Download: ML050460220 (102) | |
See also: IR 05000305/2004009
Text
February 14, 2005
EA 05-021
Mr. Craig Lambert
Site Vice President
Kewaunee Nuclear Power Plant
Nuclear Management Company, LLC
N490 State Highway 42
Kewaunee, WI 54216-9511
SUBJECT:
KEWAUNEE NUCLEAR POWER PLANT
NRC INTEGRATED INSPECTION REPORT 05000305/2004009
Dear Mr. Lambert:
On December 31, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Kewaunee Nuclear Power Plant. The enclosed integrated inspection report
documents the inspection findings which were discussed on December 17, 2004, with members
of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
This report documents one finding concerning an unknown obstruction of the containment
equipment hatch that could not be rapidly removed to ensure expeditious hatch closure would it
have been necessary to do so during the recently completed refueling outage. This finding has
potential safety significance greater than very low significance. This finding did not present an
immediate safety concern at the time it was discovered due to the availability of core cooling.
The hatch obstruction was removed within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of discovery. The finding is also an
apparent violation of NRC requirements and is being considered for escalated enforcement
action in accordance with the "General Statement of Policy and Procedure for NRC
Enforcement Actions" (Enforcement Policy), NUREG-1600. Since the NRC has not made a
final determination in this matter, no Notice of Violation is being issued for the inspection finding
at this time. Please be advised that the number and characterization of apparent violations
described in the enclosed inspection report may change as a result of further NRC review. We
will provide you with the results of our preliminary significance determination for this finding
under separate correspondence.
In addition, this report documents six NRC-identified findings and one self-revealed finding, all
of very low safety significance (Green). These findings were determined to involve violations of
NRC requirements. However, because of the very low safety significance and because the
violations were entered in your corrective program, the NRC is treating these issues as
Non-Cited Violations, in accordance with Section VI.A.1 of the NRCs Enforcement Policy. In
addition, two licensee identified violations are listed in Section 4OA7 of this report.
C. Lambert
-2-
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 copies to the Regional Administrator, U.S. Nuclear Regulatory
Commission, Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,
Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001;
and the NRC Resident Inspector Office at the Kewaunee facility.
In accordance with 10 CFR 2.390 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/
Thomas Kozak, Team Leader
Technical Support Section
Division of Reactor Projects
Docket No. 50-305
License No. DPR-43
Enclosure:
Inspection Report 05000305/2004009
w/Attachment: Supplemental Information
cc w/encl:
J. Cowan, Executive Vice President,
Chief Nuclear Officer
K. Davison, Plant Manager
Manager, Regulatory Affairs
J. Rogoff, Vice President, Counsel & Secretary
D. Molzahn, Nuclear Asset Manager,
Wisconsin Public Service Corporation
L. Weyers, Chairman, President and CEO,
Wisconsin Public Service Corporation
D. Zellner, Chairman, Town of Carlton
J. Kitsembel, Public Service Commission of Wisconsin
DOCUMENT NAME: E:\\Filenet\\ML050460220.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
RIII
RIII
NAME
RNg/trn*TKozak for
TKozak
DATE
02/14/05
02/14/05
OFFICIAL RECORD COPY
C. Lambert
-3-
ADAMS Distribution:
WDR
CFL
RidsNrrDipmIipb
GEG
KGO
JFL
CAA1
C. Pederson, DRS (hard copy - IRs only)
DRPIII
DRSIII
PLB1
JRK1
ROPreports@nrc.gov (inspection reports, final SDP letters, any letter with an IR number)
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No.:
50-305
License No.:
Report No.:
Licensee:
Nuclear Management Company, LLC
Facility:
Kewaunee Nuclear Power Plant
Location:
N 490 Highway 42
Kewaunee, WI 54216
Dates:
October 1 through December 31, 2004
Inspectors:
R. Krsek, Senior Resident Inspector
D. Jackson, Senior Resident Inspector (Acting)
P. Higgins, Resident Inspector
R. Morris, Resident Inspector, Point Beach Nuclear
Power Plant
R. Alexander, Radiation Specialist
J. Cameron, Project Engineer
M. Holmberg, Senior Reactor Engineer
J. Jandovitz, Reactor Engineer
R. Langstaff, Senior Engineering Inspector
M. Mitchell, Radiation Specialist
J. Neurauter, Reactor Engineer
R. Ng, Reactor Engineer
C. Roque-Cruz, Reactor Engineer
W. Slawinski, Senior Radiation Specialist
R. Walton, Operations Engineer
Observer:
S. Bakhsh, Reactor Engineer
Approved By:
T. Kozak, Team Leader
Technical Support Section
Division of Reactor Projects
Enclosure
2
SUMMARY OF FINDINGS
IR 05000305/2004009; 10/01/2004 - 12/31/2004; Kewaunee Nuclear Power Plant; Fire
Protection, Refueling and Outage Activities, Identification and Resolution of Problems, Event
Follow-up, Other Activities and Cross-Cutting Areas.
This report covers a 3-month period of baseline resident inspection and announced baseline
inspections of licensed operator requalification, inservice inspection, reactor pressure vessel
head replacement, emergency preparedness and the radiation protection program. The
inspections were conducted by the resident inspectors and Region III inspectors. Seven Green
Non-Cited Violations (NCVs) were identified. In addition, one apparent violation with potential
safety significance greater than Green, and two unresolved items were identified. The
significance of most findings is indicated by their color (Green, White, Yellow, Red) using
Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the
Significance Determination Process 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.
Inspector-Identified and Self-Revealed Findings
Cornerstone: Initiating Events
Green. A finding of very low safety significance was identified by the inspectors
for a violation of a fire protection License Condition. The inspectors identified
multiple examples of combustible materials either stored or in use without
specific authorization. Specifically, the licensee stored and used lubricating oil in
an emergency diesel generator room beyond that authorized by the Fire
Protection Program Analysis, the licensee stored unauthorized combustible
materials above the shelves in the working materials storage area and on top of
cabinets nearby, and the licensee stored compressed flammable gas cylinders in
the auxiliary building without authorization. Once these issues were identified,
the licensee removed the unauthorized materials. This finding was related to the
cross-cutting area of problem identification and resolution in that the NRC had
previously identified issues relating to control of transient combustible materials
above and near the working materials storage area but adequate corrective
actions were not put in place to prevent recurrence of this issue.
The finding was more than minor because the failure to adequately control
combustible materials, if left uncorrected, could become a more safety significant
concern. The finding was of very low safety significance because the issue was
a low degradation of fire prevention and administrative controls. The finding was
a Non-Cited Violation of License Condition 2.C(3) which required specific
authorization for the storage and use of combustibles in safety-related areas.
(Section 1R05.1.b.1)
Enclosure
3
Green. A finding of very low safety significance was identified by the inspectors
for a violation of a fire protection License Condition. The inspectors identified the
storage of compressed oxygen cylinders near compressed flammable gas
cylinders. Once this issue was identified, the licensee removed the stored
compressed oxygen cylinders from the area.
The finding was more than minor because the inappropriate storage of
compressed oxygen cylinders could result in greater severity of a fire affecting
equipment important to safety. The finding was of very low safety significance
because the issue was a low degradation of fire prevention and administrative
controls. The finding was a Non-Cited Violation of License Condition 2.C(3)
which required the bulk storage of compressed oxygen cylinders to be separated
from compressed flammable gas cylinders and corrective action of conditions
significantly adverse to quality to preclude recurrence. (Section 1R05.1.b.2)
Cornerstone: Mitigating Systems
Green. A finding of very low safety significance was identified by the inspectors
for a violation of a fire protection License Condition. The inspectors identified
that the licensee failed to identify pertinent information, such as the presence of
compressed flammable gas cylinders, on a fire area strategy for fire brigade
personnel. Once this issue was identified, the licensee revised the fire area
strategy for the affected area.
The finding was more than minor because the failure to provide adequate
warnings and guidance relating to hazards associated with compressed
flammable gas cylinders in fire strategies could adversely impact fire fighting
strategies used by the fire brigade in fighting a fire. The finding was of very low
safety significance due to extensive training provided to fire brigade members to
deal with unexpected contingencies. The finding was a Non-Cited Violation of
License Condition 2.C(3) which required that fire area strategies provide
pertinent information to help the fire brigade to be better prepared for fire fighting
within that area. (Section 4AO2.3.b)
Green. A finding of very low safety significance was identified by the inspectors
for a violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures,
and Drawings." The finding was associated with the licensees failure to
adequately implement scaffold control requirements contained in Procedure
GMP-127, "Requirements and Guidelines for Scaffold Construction and
Inspection," which required that scaffolding be no closer than 2 inches from any
safety-related equipment unless otherwise evaluated and approved by
Engineering. Specifically, scaffolding was erected within 2 inches of safety-
related piping for the Service Water outlet from the jacket water heat exchangers
for Diesel Generator B, the piping for the Emergency Borate MOV (CVC-440),
and Safety Injection Pump A, without engineering evaluation and approval.
Upon discovery of this condition, the licensee took immediate action to bring all
noted scaffolding problems into compliance with licensee procedures and
initiated a CAP document for the issue.
Enclosure
4
The finding was more than minor because, if left uncorrected, the issue may
have resulted in a more significant safety concern. Specifically, the failure of
scaffolding having adequate spacing in the vicinity of safety-related equipment
during a seismic event could result in damage to mitigating equipment. The
finding was of very low safety significance because it did not result in the actual
loss of the safety function of the train or system. The finding was a Non-Cited
Violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and
Drawings." (Section 1R20.1.b.1)
Green. A finding of very low safety significance was identified by the inspectors
for a violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions.
The original licensing and design basis of the containment sump screens was to
prevent any particles greater than 1/8 inch from entering the sump. The
inspectors determined that the screen size was 1/8-inch by 15/32-inch which
allowed particles greater than 1/8-inch to enter the sump. The inspectors
subsequently determined that this issue had been identified and entered into the
licensees corrective action program in 1997. However, adequate corrective
actions were not taken to correct this condition adverse to quality. Once this
issue was identified, the licensee conducted an operability determination and
concluded that there were no immediate operability issues with the containment
sump. The licensee determined that the sump screens were nonconforming in
accordance with Generic Letter 91-18, and planned long term corrective actions
to be developed in conjunction with the resolution of Generic Safety Issue 191
and NRC Generic Letter 2004-02. The inspectors concluded that the primary
cause of this finding was related to the performance characteristic of corrective
actions in the cross-cutting area of problem identification and resolution.
This finding was more than minor because the issue affected the Mitigating
System cornerstone attribute of design control for initial design and equipment
performance reliability and affected the associated cornerstone objective to
ensure the reliability and capability of systems that respond to initiating events to
prevent undesirable consequences. The finding was of very low safety
significance because it was not a design or qualification deficiency that has been
confirmed to result in a loss of function per Generic Letter 91-18. This finding
was a Non-Cited Violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective
Actions. (Section 4OA5.2.c.1)
Green. A finding of very low safety significance was identified by the inspectors
for a violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures,
And Drawings, regarding licensee instructions and procedures for containment
sump inspections. Specifically, the inspectors identified that current licensee
procedures did not require inspection or cleaning when boric acid or small debris
may be present in the containment sump. The licensees procedures for
containment coatings did not require inspection of the coating located inside the
containment sump which had not been inspected since initial application; and the
licensees procedure for containment sump gap inspections did not specify
acceptance criteria to ensure this activity was satisfactorily accomplished. The
licensee subsequently initiated several corrective actions to address these issues
which included, but are not limited to: immediate inspection and cleaning of the
Enclosure
5
safety-related containment sump; immediate inspection and assessment of the
safety-related sump concrete coating; revision of preventive maintenance
activities to require inspection and cleaning of the safety-related containment
sump every refueling outage; revision of procedures to include inspection of the
safety-related containment sump concrete coating every refueling outage; and
revision of procedures to include appropriate acceptance criteria for determining
that important activities were satisfactorily accomplished.
This finding was more than minor because if left uncorrected the finding could
become a more significant safety concern and the issue affected the Mitigating
System cornerstone attributes of equipment performance reliability and
procedure quality and affected the associated cornerstone objective to ensure
the reliability and capability of systems that respond to initiating events to prevent
undesirable consequences. The finding was of very low safety significance
because it was not a design or qualification deficiency that has been confirmed
to result in a loss of function per Generic Letter 91-18. This finding was a Non-
Cited Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings. (Section 4OA5.2.c.2)
Cornerstone: Barrier Integrity
TBD. The inspectors identified an apparent violation of 10 CFR 50, Appendix B,
Criterion V, Instructions, Procedures, And Drawings, having potential safety
significance greater than green. The finding was associated with the licensees
inability to close the containment equipment hatch in an expeditious manner
while the plant was in the refueling shutdown mode, fuel was in the reactor
vessel, the time to boil was estimated to be less than 30 minutes, and the reactor
coolant system was open to the containment atmosphere. The inability to close
the containment equipment hatch was caused by a design error in a large steel
rail system installed inside the containment which was to be used to bring heavy
equipment into the containment. This large steel rail system obstructed closure
of the containment equipment hatch. The inability to close the hatch in an
expeditious manner violated the licensees procedure requirements to do so.
This finding was more than minor because it affected the Barrier Integrity
Cornerstone objective and was associated with the Barrier Integrity Cornerstone
attribute of containment boundary preservation. Since this finding was
determined to be potentially greater than Green using the SDP Phase 2 Process,
this finding is of a to-be-determined (TBD) safety significance pending review by
the NRC Significance Determination Process/Enforcement Review Panel
(SERP). (Section 1R20.b.2)
Green. A finding of very low safety significance associated with Technical
Specification 3.8 a.1.b., Refueling Operations - Containment Closure, was self-
revealed during required daily surveillance testing of reactor building ventilation
system isolation. During the surveillance test, plant operators discovered that
radiation monitors would not cause a Reactor Building Ventilation System
Isolation to occur as designed. The cause of this failure was that other
Enclosure
6
engineered safeguards testing was in progress that disabled the Reactor
Building Ventilation System Isolation function, which was required to be operable
at the time. Once this issue was identified, the licensee promptly restored the
automatic containment ventilation isolation capability, initiated procedure
changes to prevent this issue from recurring, and entered the issue into the
corrective action program .
This finding was more than minor, because it represented a degradation of the
Barrier Integrity Cornerstone objective and was associated with Barrier Integrity
Cornerstone attribute of safety system and component and barrier performance
(containment isolation). The finding was of very low safety significance because
it did not result in the actual release of radioactive material. This finding was a
Non-Cited Violation of Plant Technical Specification 3.8.a.1.b., Refueling
Operations-Containment Closure. (Section 1R20.b.3)
B.
Licensee-Identified Violations
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 the
licensees corrective action tracking numbers are listed in Section 4OA7 of this report.
Enclosure
7
REPORT DETAILS
Summary of Plant Status
The plant operated at or near 100 percent power until operators shut it down for refueling
outage R27 on October 9, 2004. The licensee completed the outage and returned the plant to
operation on December 4, 2004. The plant remained at or near 100 percent power for the
remainder of the assessment period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness
1R01
Adverse Weather Protection (71111.01)
a.
Inspection Scope
The inspectors reviewed the facilitys design and procedures for cold weather protection,
completing one inspection procedure sample. The inspectors selectively verified
seasonal cold weather protection features for plant systems, structures and
components. This included system and area walkdowns to assess the physical
condition of weather protection features. The inspectors focused attention on
systems/components required for accident mitigation and safe reactor shutdown.
Additionally, the inspectors walked down selected plant areas to ensure that operator
actions maintained the readiness of essential systems and that accessibility of controls,
indications, and equipment would be maintained during these cold weather conditions.
The inspectors also examined the history of issues raised in the area of severe cold
weather and assessed the licensees corrective actions.
b.
Findings
No findings of significance were identified.
1R02
Evaluation of Changes, Tests, or Experiments (71111.02)
Reactor Vessel Closure Head (RVCH) Replacement (71007)
a.
Inspection Scope
From October 18, 2004, through October 22, 2004, and November 30, 2004, through
December 3, 2004, the inspectors reviewed the licensees evaluations of applicability
determination and screening questions for the design changes associated with the
RVCH replacement to determine, for each change, whether the requirements of
10 CFR 50.59 had been appropriately applied. Specifically, the inspectors reviewed
design change request No. 3481, which included a review of the function of each
changed component, the change description and scope, and the 10 CFR 50.59
screening evaluation for the following eight samples:
Enclosure
8
RVCH replacement;
RVCH insulation inside cooling shroud replacement;
control rod drive mechanism (CRDM) pressure housing assembly replacements;
removal of four unused part length CRDMs;
modification of four capped latch housing penetrations;
removal of three Conoseal flanges;
addition of three core exit thermocouple nozzle assembly flanges; and
relocation of the RVCH vent and separation from the reactor vessel level
indication system.
The inspectors used, in part, Nuclear Energy Institute (NEI) 96-07, Guidelines for
10 CFR 50.59 Implementation, to determine acceptability of the completed
pre-screenings and screening. The NEI document was endorsed by the NRC in
Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes,
Tests, and Experiments. The inspectors also consulted Part 9900 of the NRC
Inspection Manual, 10 CFR Guidance for 10 CFR 50.59, Changes, Tests, and
Experiments.
b.
Findings
No findings of significance were identified.
1R04
Equipment Alignment
.1
Partial System Walkdowns (71111.04Q)
a.
Inspection Scope
The inspectors performed partial walkdowns of the following systems, completing two
inspection procedure samples:
C
Service Water (SW) Trains A & B inside containment from containment
penetration to all Containment Fan Cooling Units; and
C
Auxiliary Feedwater in the Turbine Building
The inspectors conducted partial walkdowns of the systems listed to verify that the
systems were correctly aligned to perform their design safety function. In preparation
for the walkdowns, the inspectors reviewed the system lineup checklists, normal
operating procedures, abnormal and emergency operating procedures, and system
drawings to verify the correct system lineup. During the walkdowns, the inspectors also
examined valve positions and electrical power availability to verify that valve and
electrical breaker positions were consistent with, and in accordance with, the licensees
procedures and design documentation. The inspectors also observed the material
condition of the equipment.
b.
Findings
No findings of significance were identified.
Enclosure
9
.2
Complete System Walkdown (71111.04S)
a.
Inspection Scope
The inspectors performed a complete walkdown of the Safety Injection (SI) System to
verify that the system was correctly aligned to perform its design safety function,
completing one inspection procedure sample. In preparation for the walkdown, the
inspectors reviewed the system lineup checklists, normal operating procedures,
abnormal and emergency operating procedures, and system drawings to verify the
correct system lineup. During the walkdown, the inspectors also examined valve
positions, electrical power availability, and Control Room control switch positions to
verify that valve and electrical breaker positions were consistent with, and in accordance
with, the licensees procedures and design documentation. The inspectors also
observed the material condition of the equipment.
b.
Findings
No findings of significance were identified.
1R05
Fire Protection
.1
Fire Protection Quarterly Walkdown (71111.05Q)
a.
Inspection Scope
The inspectors performed fire protection walkdowns of the following twelve plant areas,
completing twelve inspection procedure samples:
AX-23A, Refueling Water Storage Tank Area;
AX-23B, Reactor Auxiliaries North Center;
AX-24, Fuel Handling Rooms;
AX-32, Service Rooms;
RC-60, Reactor Containment Vessel;
SC-70A, Screenhouse North;
SC-70B, Screenhouse South;
TU-90, Diesel Generator 1-A;
TU-92, Diesel Generator 1-B;
TU-95A, Dedicated Shutdown Panel Room;
TU-95B, Safeguards Alley; and
TU-95C, Auxiliary Feedwater Pump 1A Room.
During the walkdowns, the inspectors focused on the availability, accessibility, and
condition of fire fighting equipment; the control of transient combustibles and ignition
sources; and the materiel condition of installed fire barriers. The inspectors selected fire
areas for inspection based on the overall contribution to internal fire risk, and the
potential to impact equipment that could initiate a plant transient. The inspectors
verified that fire response equipment was in the designated location and available for
immediate use without obstruction; that fire detectors and sprinklers were unobstructed;
that transient material loading was within the analyzed limits; and that passive features
Enclosure
10
such as fire doors, dampers, and penetration seals were in satisfactory condition. The
inspectors verified that minor issues identified during the inspection were entered into
the licensees corrective action program (CAP).
b.
Findings
b.1
Inadequate Control of Combustible Materials
Introduction:
The inspectors identified a Non-Cited Violation (NCV) of License Condition fire
protection requirements having very low safety significance (Green) for several
examples of storing and using combustible materials without specific authorization.
Description:
Unauthorized Storage and Use of Lubricating Oil
On October 18, 2004, the inspectors observed maintenance personnel changing out the
lubricating oil for the 1A emergency diesel generator (EDG). At the time of the
inspectors observations, the used lubricating oil had been removed from the diesel
generator and transferred out of the room, Fire Zone TU-90. Maintenance personnel
had staged nine 55-gallon drums in the room and were in the process of transferring
new oil to the diesel generator.
The inspectors noted that the 4-kiloVolt (kV) switchgear for the 1-5 electrical bus for the
"A" train of safety-related equipment was located in the same fire zone adjacent to the
1A EDG. At the time of the inspectors observations, the reactor was shutdown and in
refueling operations. Fuel was in the process of being removed from the reactor and
being transferred to the spent fuel pool (SFP). The licensee had identified the B train
as the "protected" train. However, due to the amount of decay heat required to be
removed from the SFP at that time, both the 1A and 1B SFP cooling pumps were
required to be in service. The 1A SFP pump was powered from the 1-52 480-Volt
electrical bus which, in turn, was powered from of the 1-5 4-kV electrical bus which
originated in Fire Zone TU-90.
The inspectors reviewed the Fire Protection Program Analysis fire zone summary for
Fire Zone TU-90 and noted that the zone was identified as having 303 gallons of
lubricating oil located in the diesel generator as part of the combustibles for the room.
In addition, the Fire Protection Program Analysis specified that the lubricating oil was in
the EDG. However, the quantity of oil in the fire zone at the time of the inspectors
observations was approximately 495 gallons of lubricating oil, i.e., nine 55-gallon drums.
In addition, the majority of lubricating oil was being stored outside of the EDG.
Based on the discussions with site fire protection personnel, the inspectors determined
that maintenance personnel had initially requested a transient combustible permit to
bring in new lubricating oil while removing the used oil. The fire protection personnel
denied their request and directed the maintenance personnel to first remove all of the
used oil before bringing new oil into the fire zone. Maintenance personnel had
Enclosure
11
estimated that nine 55-gallon drums of lubricating oil would be necessary based on their
review of a technical manual for the EDG. The technical manual indicated that
approximately 489 gallons of lubricating oil would be necessary for a diesel generator
having an increased capacity oil pan. However, the maintenance personnel did not
recognize that the Kewaunee diesel generator had the basic oil pan, which required less
oil, in lieu of the optional increased capacity pan.
Unauthorized Transient Combustibles in Fire Zone AX-32:
The inspectors identified two examples where transient combustibles were not being
adequately controlled within Fire Zone AX-32. The examples were:
On October 19, 2004, the inspectors identified that materials, consisting of two
cardboard boxes and a plastic bucket, were stacked on top of shelving in the
working materials storage area. The materials were high enough such that a fire
in the materials would not be detected by the detectors for the automatic deluge
system. In addition, there was a potential that the materials would not be
extinguished by deluge system due to their location. The inspectors noted that
there were cables important to safety located approximately 7 feet above the
materials.
On October 20, 2004, the inspectors identified that materials were stacked on
top of a metal cabinet in a hallway on the north side of the partial height wall for
the materials storage area. The materials consisted of two cardboard boxes
labeled as containing paper towels and a third cardboard box labeled as
containing reinforced wipes. As the materials were located outside of the partial
height wall for the materials storage area, a fire in the materials would neither be
detected by the detectors for the materials storage area automatic deluge
system nor suppressed by the materials storage area automatic deluge system.
The inspectors noted that cables important to safety were located approximately
6 feet above the materials.
Unauthorized Storage of Hydrogen in Auxiliary Building
On December 1, 2004, the inspectors identified that a compressed gas cylinder
containing a flammable mixture of hydrogen (8.92 percent concentration) and nitrogen
was stored on the 586 foot elevation of the auxiliary building near door 196 in Fire
Zone 23B. The inspectors noted that procedure FPP-08-08, "FP - Control of Transient
Combustible Materials," specified designated areas for the bulk storage of large (i.e.,
greater than one pound in size) compressed flammable gas cylinders and prohibited
storage in other locations. The inspectors noted that the 586 foot elevation of the
auxiliary building was not among the designated areas and, as such, concluded that the
compressed gas cylinder was not authorized to be located there. The inspectors noted
that there were a number of overhead cable trays near the compressed gas cylinder.
One of the cable trays was designated as a safety related cable tray.
Enclosure
12
Analysis:
The inspectors determined that the specific example of bringing more lubricating oil into
Fire Zone TU-95 than what was permitted by the Fire Protection Program Analysis was
a performance deficiency. This specific performance deficiency was determined to be
more than minor because it affected the initiating events cornerstone attribute of
protection against external factors (fire) in that the amount of lubricating oil exceeded
the Fire Protection Program Analysis limit.
The inspectors determined that the specific examples of storing materials above the top
shelves in and on top of cabinets near the working materials storage working area of
Fire Zone AX-32 was a performance deficiency. The inspectors concluded that the
specific examples identified would not affect a initiating event cornerstone because
there was not enough material to develop a sufficiently large fire which would affect the
cables important to safety located directly above. However, due to the multiple
examples identified, the failure to adequately control storage and use of combustibles
could become a more significant safety concern if left uncorrected and, as such, this
performance deficiency is considered more than minor.
The inspectors determined that the specific example of storing a flammable gas cylinder
in the auxiliary building in a non-authorized location was a performance deficiency. This
specific performance deficiency was determined to be greater than minor because it
affected the initiating events cornerstone attribute of protection against external factors
(fire) in that a fire involving the compressed flammable gas cylinder could affect cables
important to safety.
The inspectors determined that, in general, failing to adequately control storage and use
of combustibles, as evidenced by multiple examples, was a performance deficiency.
The inspectors concluded that this performance deficiency could lead to a more
significant safety concern if left uncorrected. As such, the inspectors determined that
the finding associated with this performance deficiency was more than minor.
In accordance with Inspection Manual Chapter (IMC) 0609, Appendix A, "Significance
Determination of Reactor Inspection Findings for At-Power Situations," dated,
September 10, 2004, the inspectors performed a Significance Determination Process
(SDP) Phase 1 screening for the specific examples and determined that the finding was
a fire initiator contributor, i.e., an external event initiator. The inspectors performed a
Phase 1 screening in accordance with IMC 0609, Appendix F, "Fire Protection
Significance Determination Process," dated May 28, 2004, and determined that the
finding affected the fire prevention and administrative controls category. Using
Attachment 2, "Degradation Rating Guidance Specific to Various Fire Protection
Program Elements," the inspectors determined that the specific examples identified
represented low degradations. Specifically, the lubricating oil was not a low flashpoint
combustible liquid. A fire involving the observed materials in the materials storage
working area would not affect cables important to safety. Although the flammable gas
cylinder stored in the auxiliary building was comparable to low flashpoint combustible
liquids, the gas cylinder was an approved container. As such, under Task 1.3.1,
question 1, of IMC 0609, Appendix F, the inspectors determined that the finding
screened to Green and no further analysis was required.
Enclosure
13
The NRC had identified similar issues on July 12, 2004, and July 28, 2004,
(documented in Inspection Report 05000305/2004005). At that time, the licensee
initiated CAP 021822 and CAP 022025. However, the licensees corrective actions
(CAs) were insufficient to preclude recurrence. Based on the identification of multiple
examples, the inspectors concluded that the licensee's control of transient combustibles
continued to be inadequate and previous CAs were ineffective. This finding was related
to the cross-cutting area of problem identification and resolution in that the NRC had
previously identified issues relating to control of transient combustible materials above
and near the working materials storage area but adequate corrective actions were not
put in place to prevent recurrence of this issue.
Enforcement:
Kewaunee License Condition 2.C(3), required, in part, that the Nuclear Management
Company (NMC) implement and maintain in effect all provisions of the approved fire
protection program as described in the Kewaunee Nuclear Power Plant (KNPP) Fire
Plan, and as referenced in the Updated Safety Analysis Report (USAR), and as
approved in the Safety Evaluation Reports, dated November 25, 1977, and
December 12, 1978 (and supplemented dated February 13, 1981). Section 8.3 of the
KNPP Fire Protection Program Plan specified that specific authorization was required
for the storage and use of combustibles in safety-related areas. Fire zones TU-90,
AX-32, and AX-23B were safety-related areas. Contrary to the above, the inspectors
identified the following three examples of the failure to comply with License
Condition 2.C(3):
On October 18, 2004, approximately 495 gallons of lubricating oil was either being
stored or in use in the fire area TU-90. The majority of the lubricating oil was either
being stored or in use outside of the EDG. The quantity of 495 gallons was in excess of
the 303 gallons of lubricating oil specifically authorized by the Fire Protection Program
Analysis to be in fire zone TU-90. In addition, the lubricating oil was not specifically
authorized by the Fire Protection Program Analysis to be outside of the EDG. The
licensee initiated CAP 023388 and CAP 023428 to address the issue, completed
changing oil out the lubricating oil for the EDG, and removed the lubricating oil which
was outside of the EDG. The licensee initiated CAP 023388 and CAP 023428 to
address the issue. The licensee planned to revise the maintenance instructions for the
diesel generator to indicate the amount of the lubricating oil required.
On October 19, 2004, the inspectors identified that materials were stacked on top of
shelves above the working materials storage area within fire zone AX-32. In addition,
on October 20, 2004, the inspectors identified materials stacked on top of a cabinet
adjacent to the working materials storage area within fire zone AX-32. None of these
identified transient combustible materials were specifically authorized. After these
uncontrolled transient combustible materials were identified, the licensee entered the
issues into their CAP (under CAP 023418 and CAP 023478) and removed the materials.
The licensee also installed signs to inform people to not place materials on top of
shelves in the working materials storage area or on top of the cabinets in the hallway
outside the materials storage area.
Enclosure
14
On December 1, 2004, the inspectors identified that a compressed flammable gas
cylinder was stored in the auxiliary building, a safety-related area, without specific
authorization. The licensee initiated CAP 024553 to address this issue and removed the
compressed flammable gas cylinder being stored there.
Because the three examples of this violation were of very low safety significance and
were entered into the licensees CAP, it is being treated as a NCV, consistent with
Section VI.A of the NRC Enforcement Policy. (NCV 05000305/2004009-01)
b.2
Storage of Oxygen Cylinders Next to Flammable Gas Cylinders
Introduction:
The inspectors identified a NCV of License Condition fire protection requirements having
very low safety significance (Green) for the storage of compressed oxygen cylinders
next to compressed flammable gas cylinders.
Description:
On October 21, 2004, the inspectors identified two compressed oxygen gas cylinders
stored along with compressed flammable gas cylinders on the 586 foot elevation of the
auxiliary building in fire zone AX-23B near doors 196 and 255. The compressed oxygen
cylinders were within several feet of compressed flammable gas cylinders. The
compressed flammable gas cylinders consisted of four cylinders with hydrogen and
nitrogen mixtures, three cylinders with hydrogen and argon mixtures, and one propane
cylinder. The cylinders were unattended and were not separated by a barrier. The
inspectors noted that Fire Zone AX-23B was a safety-related area and that there was an
abundance of cable trays above where the compressed gas cylinders were stored. At
least one of the cable trays contained safety-related cables. Section 5.2.3.2 of
procedure FPP-08-08, "FP - Control of Transient Combustible Materials," specified that
the bulk storage of compressed oxygen cylinders shall be separated from compressed
flammable gas cylinders by a minimum of 20 feet or a noncombustible barrier at least
5 feet high having a fire resistance rating of at least 1/2 hour.
Analysis:
The inspectors determined that failing to follow procedures for the storage of
compressed oxygen cylinders near compressed flammable gas cylinders was a
performance deficiency. This performance deficiency was determined to be greater
than minor because it affected the mitigating systems cornerstone attribute of protection
against external factors (fire). Specifically, the inappropriate storage of compressed
oxygen cylinders could result in the greater likelihood or severity of a fire which affects
equipment important to safety. In accordance with IMC 0609, Appendix A, "Significance
Determination of Reactor Inspection Findings for At-Power Situations," dated
September 10, 2004, the inspectors performed a SDP Phase 1 screening and
determined that the finding was a fire initiator contributor, i.e., an external event initiator.
The inspectors performed a Phase 1 screening in accordance with IMC 0609,
Appendix FProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix F" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., "Fire Protection Significance Determination Process," dated May 28, 2004,
and determined that the finding affected the fire prevention and administrative controls
Enclosure
15
category. Using Attachment 2, "Degradation Rating Guidance Specific to Various Fire
Protection Program Elements," the inspectors determined that the finding represented a
low degradation. Under Task 1.3.1, question 1, of IMC 0609, Appendix F, the
inspectors determined that the finding screened to Green and no further analysis was
required.
Enforcement:
KNPP License Condition 2.C(3), required, in part, that the NMC implement and maintain
in effect all provisions of the approved fire protection program as described in the KNPP
Fire Plan, and as referenced in the USAR, and as approved in the Safety Evaluation
Reports, dated November 25, 1977, and December 12, 1978 (and supplemented dated
February 13, 1981). Section 8.3 of the KNPP Fire Protection Program Plan specified, in
part, that administrative procedures be in place to review, and limit if necessary, the
storage and use of combustibles during all modes of plant operation. Procedure
FPP-08-08 was the administrative procedure in place to review and limit, if necessary,
the storage and use of combustibles during all modes of plant operation.
Section 5.2.3.2 of Procedure FPP-08-08 specified, in part, that the bulk storage of
compressed oxygen cylinders shall be separated from compressed flammable gas
cylinders by a minimum of 20 feet or a noncombustible barrier. Contrary to the above,
the inspectors identified that two compressed oxygen cylinders were stored within
20 feet of compressed flammable gas cylinders with no intervening barrier. Once this
issue was identified during this inspection, the licensee entered the issue into their CAP
under CAP 023480 and CAP 023483, removed the oxygen cylinders stored in the area,
and added signs stating that oxygen cylinders should not be stored in the area.
Because this violation was of very low safety significance and it was entered into the
licensees CAP, this violation is being treated as a NCV, consistent with Section VI.A of
the NRC Enforcement Policy. (NCV 05000305/2004009-02)
.2
Fire Protection Annual Fire Drill Observation (71111.05A)
a.
Inspection Scope
The inspectors observed and evaluated the effectiveness of the fire brigade response to
a simulated fire in the plant. This inspection constituted one inspection procedure
sample. The inspectors verified that protective clothing was properly donned and was in
good condition, and that Self Contained Breathing Apparatus equipment was properly
utilized. In addition, the inspectors verified that the fire pre-plan strategy was utilized
and that all fire fighting equipment was in good condition and properly utilized. Radio
communications were effective between all stations involved in the drill. The inspectors
observed the actions of the fire brigade leader, and the manner in which he
implemented the fire pre-plan and directed his fire brigade to extinguish the simulated
fire. The fire drill plan was thorough, contained evaluation criteria, and was followed
appropriately by fire drill coordinators.
b.
Findings
No findings of significance were identified.
Enclosure
16
1R06
Flood Protection Measures (71111.06)
.1
Review of External Flood Protection Measures
a.
Inspection Scope
The inspectors performed an external flood protection inspection for the lake screen
house. This constituted one inspection procedure sample. The inspectors reviewed
USAR and related external flooding analysis to identify external flooding barriers and
vulnerabilities. The inspectors reviewed plant procedures and performed plant
walkdowns to determine the adequacy and conditions of existing flood protection
measures. The inspectors also examined the history of issues raised in the area of
flood protection and assessed the licensees CAs.
b.
Findings
No findings of significance were identified
.2
Review of Internal Flood Protection Measures
a.
Inspection Scope
The inspectors walked down and reviewed piping configurations in the following internal
flood zones, constituting one inspection procedure sample. Comparisons with the
assumptions made in the plant internal flood analysis were also made.
Zone 2B EDG 1A Room;
Zone 5B 480V Switchgear Buses 1-51 and 1-52;
Zone 3B EDG 1B room;
Zone 5B-1 480V Switchgear Buses 1-61 and 1-62; and
The inspectors evaluated internal flooding hazards in these areas and evaluated the
flood protection features, such as area doors, door gaps, and room drains to determine
whether the flood protection features were in satisfactory physical condition,
unobstructed, and capable of providing adequate flood protection. The inspectors also
reviewed design basis documents and risk analyses to determine plant vulnerabilities
and protective features for the areas inspected.
b.
Findings
Introduction:
The inspectors identified an Unresolved Item (URI) associated with the potential
vulnerability of safety-related equipment to flooding in the Turbine Building Basement.
The failure of non safety-related equipment in the Turbine Building could impact the
Enclosure
17
ability of safety-related equipment in the areas to perform their intended safety function.
The areas inspected were located immediately adjacent to the Turbine Building
Basement.
Discussion:
On September 14, 2004, the inspectors reviewed internal flood protection measures for
the AFW pump rooms, the 480-V Safeguards bus area, the safe shutdown panel area,
and the EDG 1-A and 1-B rooms, which also contained safeguards Buses 1-5 and 1-6,
respectively. These areas were located immediately adjacent to the Turbine Building
Basement. The inspectors identified a previous entry in the licensees CAP
(CAP 016375, dated May 10, 2003) regarding a flooding event which occurred on
May 9, 2003, due to a trench overflowing in the area containing the AFW pumps, the
480-V safeguards bus area, and the safe shutdown panel area, also referred to as the
safeguards alley. This trench received discharge flow from all AFW pump lube oil
coolers. At the time of the event, both AFW Pump A and B were running with lube oil
coolers discharging directly to this trench. Apparent Cause Evaluation (ACE) 002299,
written for CAP 016375, stated that at the time of this flooding event, the flocculator in
the basement of the turbine building overflowed and that a significant amount of water
was dumped to the turbine building sump located in the basement of the turbine
building and, as a result, water no longer flowed to the sump and backed up in
safeguards alley.
A review of design drawings by the inspectors revealed a direct piping connection from
the turbine building sump to the trench in safeguards alley. The inspectors determined
that there were no check valves located in the piping to prevent water spills in the
turbine building basement from backing up into the safeguards alley. The inspectors
also noted that no flood barriers specifically designed to protect equipment in the
safeguards alley from flooding in the turbine building basement were installed.
The inspectors requested additional information from the licensee regarding potential
flooding events occurring in the safeguards alley. The licensee documented its
response to the inspectors information request in Condition Evaluation (CE) 014653.
This CE stated that it would take approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> for flooding caused by
AFW pump discharge to affect safety-related equipment, and such flooding could be
mitigated by opening doors between the safeguards alley and the turbine building
basement. The CE also stated that other sources of flooding in the turbine building
basement need not be considered since such flooding events are outside the design
basis of the plant.
During a review of the licensees design basis documents, the inspectors identified that
the equipment in the safeguards alley is clearly designated with a Nuclear Safety Design
Classification of Class I, in Appendix B to the licensees USAR, Table B.2-1. In addition,
Section B.5 describes how Class I items are protected against damage, as follows:
The Class I items are protected against damage from: (a) Rupture of a pipe or tank
resulting in serious flooding or excessive steam release to the extent that the class one
function is impaired. Finally, in a letter dated September 26, 1972, the Atomic Energy
Commission requested the licensee to provide information on conditions such as
flooding that might potentially adversely affect the performance of safety-related
Enclosure
18
equipment. In a letter dated October 31, 1972, the licensee responded, in part, as
follows: It has been determined that consequences of failure of non-category I
(seismic) systems could potentially adversely affect the performance of engineered
safety systems. Specifically, the non-category I (seismic) items are the fire protection
lines in the turbine building basement and the reactor makeup water and demineralized
waterline in the auxiliary building basement. However, because of safety equipment
redundancy and design arrangement, the functional purpose of the safety equipment
would not be jeopardized in the event of failure of any of these lines. Notwithstanding
the licensees assertions, the inspectors identified additional non-category I systems and
components in the turbine building basement, including the condenser and condenser
boot seals, which could, should they fail, potentially impact the safety-related equipment
in the safeguards alley and adjacent rooms.
During plant startup at the conclusion of the 2004 refueling outage, the inspectors asked
the licensee to provide information on the operability of the AFW pumps, considering the
additional potential sources of flooding in the turbine building basement and the impact
of such flooding on the safety-related equipment in the safeguards alley, including the
AFW pumps. The licensee responded with a position paper that essentially stated that
the consideration of flooding events in the turbine building basement and their potential
impact on safety-related equipment in safeguards alley were not within the plants
licensing basis and were therefore not an operability or reportability concern. The
licensee position paper also stated that the condition should be reviewed and
compensatory actions and/or modifications should be implemented that address this
concern.
Pending additional licensee evaluation and inspector review of the potential impact of
flooding in the Turbine Building Basement on safety-related equipment located in
adjacent rooms, this issue will be treated as an URI (URI 05000305/2004009-03).
1R07
Heat Sink Performance (71111.07A)
a.
Inspection Scope
The inspectors performed an inspection of the heat exchanger performance on the 1A
EDG cooling water heat exchangers, completing one inspection sample. The heat
exchanger utilizes SW to cool the EDG during operation. The inspector observed heat
exchanger performance data gathering and software calculation of the heat removal
capability of the heat exchanger using obtained performance data, and inspected the
disassembled heat exchanger for biofouling. The inspector reviewed test acceptance
criteria and compared it against calculated test results. The inspector reviewed heat
exchanger performance calculation methodology to ensure that both instrument
uncertainty and calculation uncertainty were accounted for in the results to be compared
against test acceptance criteria. The inspector also reviewed testing frequency to
ensure that it was sufficient consistent with potential for biofouling.
b.
Findings
No findings of significance were identified.
Enclosure
19
1R08
Inservice Inspection (ISI) Activities (71111.08P)
.1
Reactor Coolant System Pressure Boundary Leakage Inspection
a.
Inspection Scope
The inspectors visually inspected the under-vessel areas, following cold shutdown of the
reactor at the beginning of the 2004 refueling outage. The reactor vessel insulation had
been removed, which allowed inspection of the bare reactor vessel metal. The thimble
guide tube penetration welds were examined for signs of boric acid deposition which
would be indicative of reactor coolant leakage. The thimble guide tubes were inspected
for any signs of boric acid streaking. The reactor vessel side walls were also examined
for any signs of boric acid streaking. The floor under the reactor vessel was inspected
for any signs of boric acid deposition. During the latter portion of the outage, following
return to normal operating pressure and normal operating temperature, the inspectors
accompanied the plants ISI team on its performance of the American Society of
Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Class 1 System
Pressure Test. This inspection included the reactor under vessel areas, the reactor
head area, as well as numerous Class 1 piping systems. During this inspection, several
reactor coolant system (RCS) leaks were identified and documented by the inspection
team. One of the leaks involved a swagelock fitting in instrument Line 33 located about
4 feet above core exit thermocouple nozzle Assembly 35, which is located on top of the
reactor head. This RCS leakage was considered by the licensee to be a high risk leak
which could produce significant degradation, if it were to contact the reactor head. After
investigating several alternatives to stop this leakage, the licensee decided to return the
plant to a cold shutdown condition, in order to repair this and other system leakage
identified during plant heat up inspections. During this cold shutdown condition, the
licensee corrected and evaluated all system leakage identified. The inspectors reviewed
licensee CAs on all leakages.
The inspectors also reviewed the documented licensee inspection results for the Class 2
Main Steam and AFW System Pressure Test. This documentation included identification
of discrepant conditions found during inspection and CA taken.
b.
Findings
No findings of significance were identified.
.2
Implementation of the Licensees ISI Program
a.
Inspection Scope
The inspectors evaluated the implementation of the licensees ISI program for
monitoring degradation of the reactor coolant system boundary and risk significant
piping system boundaries, based on a review of nondestructive examination (NDE)
records and observations.
Enclosure
20
From October 12 through 22, 2004, the inspectors evaluated several activities involving
NDE examinations with recordable indications, and welding. Specifically, the inspectors
observed the following:
Ultrasonic (UT) examination of two Safety Injection line welds (SI-W49 and
SI-W51) inside containment; and
Magnetic particle (MT) examination to Safety Injection pumps APSI-A and
APSI-B in the auxiliary building.
The inspectors selected these components in order of risk priority as identified in
Section 03 of IP 71111.08, Inservice Inspection Activities, based upon the ISI
activities available for review during the on-site inspection period. The inspectors
evaluated these examinations for compliance with the ASME Boiler and Pressure
Vessel Code Section XI and plant Technical Specification (TS) requirements and to
determine whether indications and defects (if present) were dispositioned in accordance
with the ASME Code.
The inspectors reviewed the licensees records related to disposition of recordable
indications identified in four examinations. Specifically, the inspectors reviewed the
evaluation records with recordable indications accepted for continued service for:
The reactor vessel closure head flange and control rod drive mechanism
RV-W12;
The steam generators SG-1A and SG-1B;
The seal water injection filters AF SI-1A and AF SI-1B; and
The RC-RTD line for reactor coolant loop B.
The inspectors evaluated the disposition of indications identified during these
examinations for compliance with the requirements of the ASME Code Section XI.
The inspectors reviewed the licensees records related to pressure boundary welding
performed in the following components:
3-inch motor operated valves, PR1A/MV32089 and PR1B/MV32090;
pressurizer power operated relief valve (PORV) block valve; and
3-inch check valve at the Auxiliary Feedwater Pump Discharge at Steam
Generator 1B.
The inspectors performed this review to determine whether the welding acceptance and
pre-service examinations (e.g., pressure testing, visual, dye penetrant, and weld
procedure qualification tensile tests and bend tests) were performed in accordance with
the requirements of the ASME Code, Sections III, V, IX, and XI.
The above review constituted one inspection procedure sample.
From October 12, 2004, through October 22, 2004, the inspectors reviewed a sample of
licensee activities related to the Boric Acid Corrosion Control program. This review
included:
Enclosure
21
direct observation of licensee staff performing a walkdown of systems inside
containment, in part to identify evidence of boric acid leakage;
review of two engineering evaluations performed for boric acid found on reactor
coolant system piping and components;
interviews with licensee staff involved in boric acid program; and
review of corrective actions performed for evidence of boric acid leaks.
These observations and reviews were performed to confirm that:
licensee visual inspections emphasized locations where boric acid leaks can
cause degradation of safety significant components;
degraded or non-conforming conditions are properly identified in the licensees
corrective action system;
ASME Code wall thickness requirements were maintained; and
corrective actions were consistent with requirements of the ASME Code and
10 CFR Part 50, Appendix B, Criterion XVI.
The review discussed above constituted one inspection sample.
The activities that were not available for inspectors review for this inspection are
identified in the table below.
7111108 Section
Number
Reason Activity was
Unavailable For
Inspection
Reduction in Inspection
Procedure Samples
Section 02.02 Vessel
Upper Head
Inspection Activities.
The licensee did not
perform vessel upper
head inspection activities
during this outage
(Reactor Vessel Head
Replacement).
The inspectors concluded
that these unavailable
activities constituted a
reduction by two from the
total number of procedure
samples required by
Section 71111.08-5 of
Section 02.04. Steam
Generator (SG) Tube
Inspection Activities.
The licensee did not
perform SG tube
inspection activities
during this outage
b.
Findings
No findings of significance were identified.
Enclosure
22
1R11
Licensed Operator Requalification (71111.11Q)
.1
Observation of Licensed Operator Simulator Training
a.
Inspection Scope
The inspectors observed licensee training personnel evaluate an operating crew during
an accident scenario and subsequently observed the operating crew critique their
performance. The inspectors observed the crew and verified the following attributes of
crew performance: communications, alarm response, emergency operating procedure
usage, component operations and emergency plan classifications. The inspectors
reviewed the scenario for operational validity and risk significance. The inspectors
discussed scenario observations and crew evaluations with the licensee trainers. In
addition, the inspectors reviewed the licensees baseline fidelity study to ensure that
differences between the simulator and actual control room board configuration were
maintained as close as possible. This constitutes one quarterly inspection sample.
b.
Findings
No findings of significance were identified.
1R12
Maintenance Effectiveness (71111.12Q)
a.
Inspection Scope
The inspectors reviewed the implementation of the Maintenance Rule for the Residual
Heat Removal (RHR) system, completing one inspection sample. The inspectors
verified that the licensee identified, entered, and scoped component and equipment
failures within the maintenance rule requirements. The inspectors also verified that the
systems and equipment were properly categorized and classified as (a)(2) in
accordance with 10 CFR 50.65. The inspectors reviewed a sample of maintenance
work orders, action requests, functional failure evaluations, unavailability records, and a
sample of condition reports (CRs) to verify that the licensee identified issues related to
the Maintenance Rule at an appropriate threshold and that CAs were appropriate.
Additionally, the inspectors reviewed the licensees performance criteria to verify that the
criteria adequately monitored equipment performance. The inspectors discussed
identified deficiencies with the licensee. The licensee documented these deficiencies on
CRs.
b.
Findings
No findings of significance were identified.
1R13
Maintenance Risk Assessment and Emergent Work Evaluation (71111.13)
a.
Inspection Scope
The inspectors reviewed the licensees evaluation and assessment of plant risk,
scheduling, and configuration control during the following planned and emergent work
Enclosure
23
activities. Shutdown Safety Assessment Checklists and associated compensatory and
component protection measures were inspected during the following 4 weeks of the
licensees refueling outage K27, constituting completion of four inspection samples:
Week of October 11, 2004;
Week of October 18, 2004;
Week of October 25, 2004; and
Week of November 1, 2004.
In particular, the inspectors evaluated the licensees planning and management of
maintenance and verified that shutdown risk was acceptable and monitored in
accordance with the requirements of 10 CFR 50.65(a)(4), except as noted in
Section 1R20.b.2 of this report. Additionally, the inspectors compared the assessed risk
configuration against the actual plant conditions and any in-progress evolutions or
external events to verify that the assessment was accurate, complete, and appropriate.
The inspectors also reviewed licensee actions to address increased shutdown risk
during these periods to verify that the actions were in accordance with approved
administrative procedures.
b.
Findings
No findings of significance were identified.
1R14
Personnel Performance During Non-Routine Plant Evolutions (71111.14)
.1
Increased Unidentified Leakage in Containment.
a.
Inspection Scope
On September 28, 2004, the control room received a Containment Sump A Level High
Alarm. This alarm was not expected and on September 29, 2004, the licensee made a
containment entry in an attempt to determine the source of the leakage. The resident
inspector accompanied licensee personnel into the containment during this entry. The
licensee was not able to identify the source of leakage into the sump. The licensee
calculated the approximate leak rate and found it to be within acceptable limits.
However, the licensee determined that this leak rate represented a significant increase
in leakage into the containment sump over the leakage that had been routinely
experienced during this operating cycle. The licensee determined by chemical analysis
that the water leakage into the sump was from the service water system. On
September 30, 2004, the sump high-level alarm was again received and the sump was
pumped out.
On October 2, 2004, the sump high-level alarm was received and two additional
containment entries were made by the licensee to inspect Containment Fan Coil
Units A and B. The resident inspector accompanied licensee personnel on these two
containment entries. No indications of leakage were noted. Additional containment
entries were made by the licensee to inspect Containment Fan Coil Units C and D.
Again, no indications of leakage were noted.
Enclosure
24
On October 3, 2004, the sump high-level alarm was again received and additional
containment entries by the licensee determined that the leakage originated at the
Shroud Cooling Units. Additional chemical analysis performed by the licensee on the
water leaking into the sump confirmed that it was from the service water system and not
reactor coolant. The Shroud Cooling Units were isolated in an attempt to stop the
leakage into the containment sump. Following isolation, the leakage into the sump was
reduced but it did not stop, indicating that the Shroud Cooling Units SW isolation valves
were leaking. The Shroud Cooling Units are non safety-related components and are
isolated on a SI signal. Licensee personnel determined that the leakage past the
isolation valves was insignificant and would not affect the operability of the Containment
Fan Coil Units. On October 9, 2004, the plant entered a refueling outage. Detailed
inspection of the Shroud Cooling Units by the licensee confirmed that the leakage was
coming from these units. Repairs to these units were made prior to plant startup at the
end of refueling outage.
This review constituted one inspection sample.
b.
Findings
No findings of significance were identified.
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors reviewed the following operability evaluations, completing two inspection
samples:
Control Room Exclusion Zone As Found Air Flows Not per Design Basis; and
Turbine-Driven AFW Pump Outboard Bearing Oil Level Above Normal Band.
The inspectors reviewed design basis information, the Updated Final Safety Analysis
Report, TS requirements, and licensee procedures to verify the technical adequacy of
the operability evaluations. In addition, the inspectors verified that compensatory
measures were implemented, as required. The inspectors verified that system
operability was properly justified and that the system remained available, such that no
unrecognized increase in risk occurred.
b.
Findings
No findings of significance were identified.
1R16
Operator Workarounds (71111.16)
a.
Inspection Scope
The inspectors reviewed previously identified operator workarounds, equipment
deficiency logs, and control room deficiencies to verify that the workarounds did not
create significant adverse consequences regarding the reliability, availability, and
operation of accident mitigating systems, completing one inspection procedure sample
Enclosure
25
of individual operator workarounds. The inspectors also assessed the effects of the
workarounds on the ability to implement abnormal and emergency response procedures
in a correct and timely manner. In addition, the inspectors reviewed any emergent risk
significant operator workarounds to determine if the functional capability of a system or
human reliability of an initiating event was affected.
Inspectors also assessed the cumulative affects of the current listing of operator
workarounds for impacts on equipment reliability, availability, and a potential for
equipment mis-operation. Impact of these workarounds were also assessed for
negative affects on multiple mitigating systems, for the impact on operator actions
required to respond to plant events and transients. This constituted completion of one
inspection procedure sample of the cumulative affects of operator workarounds.
b.
Findings
No findings of significance were identified.
1R17
Permanent Plant Modifications (71111.17A)
.1
Control Rod Guide Tube Split Pin Replacement
a.
Inspection Scope
The inspectors reviewed the engineering analyses, design information and modification
documentation for the replacement of the Control Rod Guide Tube Split Pins and the
installation of a Fuel Assembly Sized Debris Cannister which occurred during the
October 9, 2004, refueling outage. The Control Rod Guide Tube Split Pins restrained
the lower end of the control rod guide tubes in the reactor vessel. The Fuel Assembly
Sized Debris Canister was provided for the storage of radioactive split-pin-related debris
in the Spent Fuel Pool. This inspection constituted one inspection sample. The
inspection activities included, but were not limited to, verification and review of the
following parameters associated with this modification: structural integrity, material
compatibility, environmental qualification, safety classification, functional properties,
seismic qualification, failure mode potentials, and the associated 10 CFR 50.59
screening analysis. Additionally, the inspectors observed portions of the installation and
testing of the split pins, reviewed acceptance testing results, and reviewed CRs
associated with the design change to verify that the licensee identified and documented
problems at an appropriate threshold.
b.
Findings
No findings of significance were identified.
1R19
Post-Maintenance Testing (71111.19)
a.
Inspection Scope
The inspectors reviewed the post-maintenance testing activities associated with the
following scheduled and emergent work activities, completing three inspection samples:
Enclosure
26
Containment Fan Cooling Units A, B, C and D;
EDG B Inspection and Operational Testing; and
RHR Pump B Overhaul Testing;
The inspectors verified that the testing was adequate for the scope of the maintenance
work performed. The inspectors reviewed the acceptance criteria of the tests to ensure
that the criteria was clear and that testing demonstrated operational readiness
consistent with the design and licensing basis documents.
The inspectors attended pre-job briefings to verify that the impact of the testing was
appropriately characterized. The inspectors also observed the performance of testing to
verify the procedure was followed and that all testing prerequisites were satisfied.
Following the completion of each test, the inspectors walked down the affected
equipment to verify removal of the test equipment and to ensure the equipment could
perform the intended safety function following the test. The inspectors also reviewed
the completed test data to ensure the test acceptance criteria were met for the post
maintenance testing.
b.
Findings
No findings of significance were identified.
1R20
Refueling and Outage (71111.20)
a.
Inspection Scope
The inspectors observed the licensees performance during refueling outage R27, which
commenced on October 9, 2004, completing one inspection sample. The inspectors
reviewed the Outage Plan Schedule prior to commencement of the outage to assess
licensee response to periods of increased risk. The review included planned mitigating
actions for periods of increased risk. The reactor shutdown was monitored including
periods from initial power reduction to completion of plant cool down to cold shutdown.
Specific attention was paid to reactivity control during plant power changes, the reactor
shutdown, and boration in preparation for plant cool down. During plant cool down,
rates of cool down were monitored to ensure that maximum rates were not exceeded.
During the course of the outage, licensee activities were monitored to ensure that
systems relied upon for reactor core cooling were maintained in appropriate
configurations based on a valid assessment of risk for that point in the outage.
Refueling activities were inspected to ensure that fuel handling was conducted in
accordance with plant procedures and TSs. Finally, plant heat up and start up activities
were inspected to ensure compliance with station procedures and TSs.
The inspectors performed the following observations on a frequent basis:
Outage Management Outage Control Center turnover meetings to assess
sensitivity of the licensee to periods of increased plant risk;
Control Room panel walkdowns to inspect current configuration of systems
required to remove reactor core decay heat;
Enclosure
27
CAP issue screening meetings to observe sensitivity to issues identified that
could potentially impact plant risk;
In plant evolutions and on-going work to ensure that systems needed for reactor
core cooling, and other required safety functions were being appropriately
considered and required protected equipment was properly designated;
Shutdown Safety Assessment Checklist Reviews to ensure levels of shutdown
risk were as expected and the plant configuration matched periodically updated
safety assessments; and
During the extended outage period when the reactor core was fully offloaded to
the SFP, the inspectors performed walkdowns at least weekly of the SW system
supply to the SFP Cooling system, the SFP Cooling system, and the Normal and
Electrical Power Supplies to SFP Cooling Pumps.
The inspectors performed the following specific inspection activities:
A tag-out walkdown of the A SW system, to ensure that all boundaries were
appropriate for the plant and work conditions, all components were correctly
positioned, and all safety tags were correctly placed;
A tag-out walkdown of the B EDG, to ensure that all boundaries were
appropriate for the plant and work conditions, all components were correctly
positioned, all safety tags were correctly placed, no tagged components
negatively impacted the opposite train, and barriers were in place to protect the
A EDG;
A tag-out walkdown of the SFP Cooling Filter and Pre-Filter, to ensure that all
boundaries were appropriate for the plant and work conditions, all components
were correctly positioned, and all safety tags were correctly placed;
An inspection of the SFP Cooling System with the core fully offloaded to the SFP
during a period of elevated risk with the A SW System out-of-service. The SW
System provided cooling to the SFP Heat Exchangers, and thus was the ultimate
heat sink for the fuel offloaded to the SFP. The inspectors verified proper
functioning and material condition of the SFP Cooling System, and protection of
equipment and areas during the period of elevated risk;
An inspection of electrical power supplies supporting SFP operation while the
core was fully offloaded to the SFP. The electrical alignment was correct for the
given plant conditions, and supported operation of both SFP Cooling pumps from
independent power supplies. In addition, the SW System electrical alignment
was proper such that cooling was being supplied to the SFP Heat Exchanger;
An inspection of Root Cause Evaluation (RCE) 612 Temporary Procedure
Change Used To Inadvertently Bypass a Hold Card was completed using
Inspection Procedure (IP) 71152 Identification and Resolution of Problems to
determine the adequacy of the threshold for the initiation of CAs and to
Enclosure
28
determine the completeness of CAs associated with the evaluation. In this case,
the licensee adequately addressed the root and contributing causes in the
evaluation in their CAP. Resolution actions were completed in sufficient detail
and in a timely fashion. Each item was reviewed by the licensees Corrective
Action Review Board (CARB) to determine if proposed and completed CAs
would sufficiently resolve the issue. In addition, an effectiveness review was
conducted for the completed CAs;
An inspection of RCE 616 Damaged Rod Control Cluster Assembly was
completed using IP 71152 Identification and Resolution of Problems to
determine the adequacy of the threshold for the initiation of CAs and to
determine the completeness of CAs associated with the evaluation. In this case,
the licensee adequately addressed the root and contributing causes in the
evaluation in their CAP. Resolution actions were completed in sufficient detail
and in a timely fashion. Each item was reviewed by the licensees CARB to
determine if proposed and completed CAs will sufficiently resolve the issue. In
addition, an effectiveness review was conducted for the completed CAs;
A tag out walkdown of the Flux Map Electrical System was conducted to ensure
proper protection against incore thimble movement was in place for the Under
Vessel Penetration Inspection. This walkdown included confirmation that all
boundaries were appropriate for the plant and work conditions, all components
were correctly positioned, and all safety tags were correctly placed;
An inspection of offsite and onsite electrical power supplies supporting RHR
operation was conducted while the core was fully loaded. The electrical
alignment was correct for the given plant conditions, and supported operation of
both RHR pumps from independent power supplies. In addition, the Component
Cooling Water electrical and mechanical system alignments were proper such
that cooling was being supplied to the RHR heat exchangers;
An inspection of decay heat removal systems was performed while the core was
fully loaded. Designated decay heat removal systems, including both trains of
the RHR System and both Steam Generators, were reviewed to ensure full
availability and that these systems were monitored and protected as required by
plant procedures and orders. The identified decay heat removal systems were
correct for the given plant conditions and as designated in the Shutdown Safety
Assessment. In addition, the control room monitoring of the decay heat removal
capability and system performance was properly conducted;
An inspection of the SFP Cooling System was conducted with the core fully
offloaded to the SFP during a period of elevated risk with the 480-V power
supplies to the SFP Pumps crosstied. This crosstie was established to allow
work on the 4 Kv safeguards buses while still providing power to both SFP
Pumps. The inspectors found the SFP Cooling System to be functioning
properly, and in adequate physical condition. In addition, appropriate equipment
and areas were protected by barriers during the period of elevated risk;
Enclosure
29
An inspection of reactivity control practices was conducted with the core fully
loaded. Potential boron dilution paths were identified, procedures for ensuring
proper boron concentration and mixing were reviewed and control room
practices for monitoring these parameters were observed. The inspectors found
dilution paths properly identified, boron concentration in accordance with
procedures and control room monitoring practices properly conducted;
An inspection of the SW supply to the vital equipment was conducted with the
core fully loaded. The inspectors walked down the valve, pump and heat
exchanger line ups including the electrical supplies. The inspectors found the
SW Cooling System to be functioning properly, and in adequate physical
condition. In addition, appropriate equipment and areas were protected by
barriers during the period of elevated risk to core cooling;
An inspection of the plants ability to close the containment equipment hatch in
preparation for reactor vessel head lift was performed with the vessel fully loaded
with spent fuel. A large steel rail system was installed inside the containment
which was used to bring heavy equipment into the containment. The inspectors
reviewed procedure and plans, including two specifically generated to ensure
rapid removal of this rail system and walked down the containment hatch area.
The inspectors found that the licensee was unable to close the containment
equipment hatch in expeditious manner. (Section 1R20.1.b.2)
The inspectors conducted a total of four containment walkdown inspections
prior to containment closeout at the end of the refueling outage. The inspection
included all levels interior to the containment, as well as the containment annulus
area. The inspectors looked for any debris, equipment, tools or other items
which should be removed prior to containment closeout. The inspectors also
looked for any significant system leakage or other system discrepancies which
would require correction prior to containment closeout. The emergency core
cooling system sump basement level was inspected to ensure that any loose
material which could affect sump post-accident effectiveness was identified and
removed. The area under the reactor vessel as well as the upper refueling cavity
area and the area on top of the head were inspected. The area between the
inner containment hatch and the outer containment shield block hatch was
inspected to ensure proper closure of both hatches. Any material, tools, or
equipment which the licensee intended to leave in the containment during plant
operation were inspected to ensure they were properly tied down. All
discrepancies identified by the inspectors during these walkdowns were turned
over to the licensee for disposition and were properly disposition by the licensee;
and
The inspectors conducted an inspection of plant start up activities to include
portions of plant heat up, approach to criticality via dilution, and plant
synchronization to the electrical grid. Start up evolutions were conducted in
accordance with station approved procedures listed in the reference section.
Enclosure
30
b.
Findings
.1
Scaffolding Erected Too Close to Safety-Related Equipment Required To be Operable
Introduction:
A finding of very low significance (Green) was identified by the inspectors for a violation
of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings having
a very low safety significance. During walkdowns of areas where scaffolding had been
erected to support outage activities, the inspectors identified several examples in which
the licensee placed scaffolding closer than 2 inches from safety-related equipment
without evaluation and approval by Engineering.
Description:
On October 6, 2004, with the plant at 100 percent power, the inspectors performed
walkdowns of plant areas to review outage preparation activities associated with
Refueling Outage R27. Scaffolding was being erected throughout the plant. Licensee
procedure GMP-27, Requirements and Guidelines for Scaffold Construction and
Inspection, required that scaffolding not be erected within 2 inches of safety-related
equipment, unless an engineering evaluation had been completed demonstrating that
operability of the equipment had not been adversely impacted. The inspectors identified
four areas in which scaffolding had been erected closer than 2 inches from safety-
related equipment and an engineering evaluation had not been completed to ensure that
equipment operability was not negatively impacted. The four areas included:
B EDG - A scaffold pic was in direct contact with the SW cooling outlet line from
the cooling water heat exchangers. The cooling water heat exchangers were
safety-related equipment. The licensee had not prepared an engineering
evaluation to ensure that operability of the B EDG, or its support systems were
not negatively impacted;
A SI Pump - Multiple pieces of scaffold were in direct contact and within 2
inches of components and piping associated with the pump. The licensee had
not prepared an engineering evaluation to ensure that operability of the A SI
pump, or its support systems were not negatively impacted;
A Internal Containment Spray (ICS) Pump - A scaffold pic was in direct contact
with ICS piping in the north penetration area. The licensee had not prepared an
engineering evaluation to ensure that operability of the A ICS pump, or its
support systems were not negatively impacted; and
Emergency Borate MOV (CVC-440) - A scaffold pic was in direct contact with the
motor associated with the MOV. The licensee had not prepared an engineering
evaluation to ensure that operability of the Emergency Borate MOV was not
negatively impacted.
All of the above listed components were required to be operable for the plant operating
condition at the time of discovery.
Enclosure
31
Analysis:
The inspectors determined that the failure to erect scaffolding near safety-related
equipment in accordance with licensee procedure GMP-27, Requirements and
Guidelines for Scaffold Construction and Inspection, was a performance deficiency
warranting a significance determination. The finding was more than minor since it
impacted the Mitigating Systems Cornerstone objective of ensuring the availability,
reliability, and capability of systems that responded to initiating events to prevent
undesirable consequences. The inspectors evaluated the finding using IMC 0609,
Appendix AProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix A" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., Phase 1 screening and determined that the finding was of very low safety
significance because there was no actual loss of function of any of the systems.
Enforcement:
10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures, and Drawings, required
that activities affecting quality be prescribed by documented instructions, procedures, or
drawings, and that activities be accomplished in accordance with these instructions,
procedures, or drawings. Licensee procedure GMP-27, Requirements and Guidelines
for Scaffold Construction and Inspection, a procedure affecting quality, required that
scaffolding not be erected within 2 inches from safety-related equipment, unless an
engineering evaluation had completed demonstrating that operability of the equipment
had not been negatively impacted. Contrary to this requirement, the licensee erected
scaffolding in direct contact with, or within 2 inches from the SW cooling outlet line from
the cooling water heat exchangers of the B EDG; components and piping associated
with the A SI pump; piping associated with the A ICS pump; and the motor associated
with the Emergency Borage MOV. This safety-related equipment was required to be
operable based on the operating condition of the plant, and the licensee had not
completed an engineering evaluation to demonstrate that the operability of any of the
equipment was not negatively impacted. Therefore, the inspectors determined that this
finding was a violation of 10 CFR 50, Appendix B, Criterion V. The licensee took
immediate action to bring all noted scaffolding problems into compliance with
procedural requirements. The licensee initiated a CAP document for the issue
(CAP 023040). Because this violation was of very low safety significance (Green) and
documented in the licensees corrective action program, this finding is being treated as a
NCV, consistent with Section VI.A of the NRC Enforcement Policy.
.2
Inability to Close Containment Equipment Hatch
Introduction:
A finding of safety significance yet to be determined was identified by the inspectors for
an apparent violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures,
And Drawings. The licensee was unable to close the equipment hatch in an
expeditious manner while the plant was in the refueling shutdown mode, spent fuel was
in the reactor vessel, the time to boil was estimated to be less than 30 minutes, and the
RCS was open to the containment atmosphere.
Enclosure
32
Description:
Kewaunee entered a refueling and reactor vessel head replacement outage on
October 9, 2004. On October 10, the licensee removed the containment equipment
hatch. On October 11, the licensee installed steel runway tracks inside and outside of
containment to facilitate reactor vessel head replacement activities. It was the
licensees intent to be able to quickly close the equipment hatch when needed by
simply moving the exterior track. Also on October 11, a pressurizer safety valve was
removed which vented the reactor coolant system to the containment atmosphere. On
October 12, Diesel Generator 1A was removed from service. On October 13,
detensioning of the reactor vessel head began, which further vented the reactor coolant
system to the containment atmosphere.
On October 14, with reactor coolant time to boil estimated to be less than 30 minutes, in
preparation for lifting the reactor vessel head, the licensee was required by TSs to close
the hatch. The licensee removed the exterior track and attempted to close the hatch.
However, the design of the interior track did not take into consideration the curvature of
the equipment hatch. Due to this design flaw, the interior track interfered with the
closure of the hatch. There were no procedures or plans in place to modify or remove
the interior steel runway track rapidly, no tools were staged to modify or remove the
interior steel runway track, no personnel were trained to rapidly remove the interior steel
runway track, and unsecured heavy material rested on the interior steel runway track
and erected scaffolds were adjacent to the interior steel runway track. These factors
complicated the decision making process on removal of the interior track and would
have been unknowingly encountered in case of an emergency, thus complicating any
attempt to rapidly remove the track. The licensee decided to cut away a portion of the
interior track so that it would no longer interfere with the hatch.
Following removal of the interference, difficulties were encountered by plant
maintenance staff in bolting the hatch in place in accordance with plant procedure
CMP 89A-2, which called for using four specific bolts, due to the unavailability of
correctly sized ladders. Containment equipment hatch closure was achieved
approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the discovery of the interference. Later in the outage on
Nov. 13, 2004, plant personnel again had difficulties closing the hatch. In this instance,
six bolts were used to secure the hatch instead of four as called for by the procedure.
The inability of the licensee to close the hatch in an expeditious manner with the reactor
coolant system vented to containment, time to boil less than 30 minutes, and one diesel
generator out-of-service, was considered by the inspectors to be a potentially risk
significant condition. Therefore, this issue was evaluated using the significance
determination process.
Analysis:
MC 0308, Significance Determination Process Basis Document, Attachment 3,
Section 5, Performance Deficiency Basis, states that the definition of a performance
deficiency requires the staff to make a reasonable determination that the licensee
intended to meet some requirement or standard and they did not. Such a requirement
need not be directly imposed by the NRC. Licensee good operating practices are
Enclosure
33
expected as a means to ensure safety and minimize risk, and may be implemented as
initiatives that go beyond regulatory requirements (e.g. management of shutdown safety
by following industry-developed guidelines).
NUMARC 91-06 is an industry standard which provides guidelines for industry actions to
assess shutdown risk. NUMARC 91-06, Section 4.1.1, states that containment hatches
and other penetrations that communicate with the containment atmosphere should
either be closed or capable of being closed prior to core boiling following a loss of decay
heat removal and should be addressed in procedures. The licensee implemented
initiatives to ensure safety and minimize risk by developing procedures to enable the
hatch to be closed if needed. However, due to the poor design of the track, the licensee
was unable to meet this procedural guidance during this event. The licensee had
numerous opportunities to identify the poor track design. Therefore, based on the
statements in MC 0308 and the guidance in MC 0612, this is considered a performance
deficiency requiring a significance determination.
The finding was assessed under the IMC 0609, Appendix A, Attachment 1 worksheet for
Containment Barriers Cornerstone. The finding was determined to represent an actual
open pathway in the physical integrity of reactor containment. As a result, Appendix H
of IMC 0609 was used to determine the significance of the finding.
The finding was determined to be a Type B finding (affects only LERF, not CDF) at
shutdown. Table 6.3 of IMC 0609, Appendix H is the phase 1 screening for these types
of findings. The Kewaunee containment is a PWR, large, dry containment. The
containment status was determined to be intact because the licensee planned to
maintain an intact containment and the finding involved the failure to maintain the ability
to close containment. The SSC specifically affected by the finding is the containment
equipment hatch which was determined to fit the category of containment penetration
seals, isolation valves, vent and purge systems. The phase 1 assessment resulted in
the need to perform a phase 2 assessment.
Phase 2 risk evaluation
Assumptions
The plant was determined to be in POS 2E which represents cold shutdown with
the reactor coolant system (RCS) vented, steam generators not available, and
within 8 days of shutdown (decay heat high).
The finding occurred approximately 64 hours7.407407e-4 days <br />0.0178 hours <br />1.058201e-4 weeks <br />2.4352e-5 months <br /> into the shutdown.
The finding existed for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The total time that the containment
equipment hatch was open and could not be closed was approximately 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br />.
During this 80 hour9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> period, the RCS was open for approximately 76 hours8.796296e-4 days <br />0.0211 hours <br />1.256614e-4 weeks <br />2.8918e-5 months <br /> due to
the removal of a pressurizer safety valve and also due to de-tensioning of the
reactor vessel head studs. For approximately 67 hours7.75463e-4 days <br />0.0186 hours <br />1.107804e-4 weeks <br />2.54935e-5 months <br /> of this period, an
emergency diesel generator was unavailable.
The following equipment was available for the duration of the finding:
Enclosure
34
Both SI pumps
Both RHR pumps
All charging pumps
All service water pumps
Both containment spray pumps
One EDG
Two offsite power sources
The time to boil during this period was estimated by the licensee to be less than
30 minutes.
Given these assumptions, the finding was determined to have potential significance
greater than very low significance. Therefore, this finding will be evaluated using the
Significance and Enforcement Review Process and a preliminary significance
determination for the finding will be provided to the licensee under separate
correspondence.
Enforcement:
10 CFR Part 50, Appendix B, Criterion V, (Instructions, Procedures, and Drawings)
requires, in part, that activities affecting quality be prescribed by documented
instructions, or procedures of the type appropriate to the circumstances and shall be
accomplished in accordance with these instructions, or procedures. Plant procedure
CMP-89 A-02, Containment Building Inner Equipment Door Opening and Closing
Instructions, a procedure affecting quality, required that any equipment which passes
through and could obstruct containment hatch closure be designed to allow rapid
removal in order to ensure expeditious containment building equipment hatch closure
should it become necessary to do so. Contrary to the above, on October 11, 2004, the
licensee installed a interior steel runway track which passed through and obstructed
containment hatch closure. The track was not designed to allow rapid removal. This
finding did not present an immediate safety concern at the time it was discovered due to
the availability of core cooling. The hatch obstruction was removed within hours of
discovery and the licensee has initiated a root cause investigation to develop long term
corrective actions for this issue. Pending determination of the findings safety
significance, this finding is considered an apparent violation of NRC requirements
.3
Reactor Building Ventilation Isolation Function Not Available When Required
Introduction:
A Non-Cited Violation (NCV) of TSs was self-revealed. This NCV was characterized as
being of very low safety significance (Green). It became apparent during required daily
surveillance testing that radiation monitors would not cause an automatic Reactor
Building Ventilation System Isolation to occur as designed.
Enclosure
35
Description:
On November 18, 2004, at approximately 0803 hours0.00929 days <br />0.223 hours <br />0.00133 weeks <br />3.055415e-4 months <br />, technicians began surveillance
procedure SP-55-155C, Engineered Safeguards Prestartup Logic Test with the
approval of shift operations. The test placed both trains of Engineered Safeguards in
Test for the duration of the procedure. By placing Engineered Safeguards in Test,
valid alarm signals from Radiation Monitors R-12 (Containment Vessel Air Monitor) and
R-21 (Containment System Vent Activity Monitor) would not actuate a Reactor Building
Ventilation Isolation, such that valves CBV-1, CBV-2, CBV-3, and CBV-4 would not
automatically close. These valves would have closed in manual, and would be manually
closed per procedure by control room operators in the event of a Radiation Monitor
Alarm from either R-12 or R-21. During the period of time when the Reactor Building
Ventilation Isolation was defeated, the licensee placed the reactor upper internals into
the reactor. At 1630 on the same day, operations personnel conducted a required daily
surveillance test that tested the R-12 and R-21 systems ability to generate a Reactor
Building Ventilation Isolation. During this test, the R-12 was tested and alarmed
properly. However, operators recognized that a Reactor Building Ventilation Isolation
failed to occur and that the surveillance test had failed. A short investigation ensued
where it was determined that the Engineered Safeguards Prestartup Logic Test had
defeated the ability for a radiation monitor alarm to generate an automatic Reactor
Building Ventilation Isolation.
Analysis:
The inspectors determined that a performance deficiency existed in that the Engineered
Safeguards System was allowed to be placed in Test thus defeating the Reactor
Building Ventilation Isolation system function during a period that it was required to be
operable by TS 3.8 a.1.b Refueling Operations- Containment Closure. This finding
was more than minor because it represented a degradation of the Barrier Integrity
Cornerstone objective and was associated with Barrier Integrity Cornerstone attribute of
safety system and component (SSC) and barrier performance (containment isolation
SSC reliability).
The inspectors completed a significance determination of this issue using IMC 0609,
Appendix HProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix H" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., Containment Integrity Significance Determination Process. The entry
condition identified was that a degraded condition affecting the Containment Barrier
Integrity potentially increased Large Early Release Frequency (LERF) without affecting
Core Damage Frequency (CDF). For this event, the Plant Operating State (POS)
During Shutdown is defined as POS 3 (Reactor Cavity Level is at Refueling Level). The
time window that applied for this event was the Late time window since there was very
low decay heat load. The issue was determined to be a Type B finding since the
problem was related to containment integrity without affecting the likelihood of core
damage. Section 6.2 of IMC 0609, Appendix H, Approach for Addressing Type B
Findings At Shutdown, defined the process for performing a Phase 2" analysis of this
issue. Step 2.1 stated that if the performance deficiency was not related to POS 1 or
POS 2 and in the Early time window, then the performance deficiency was
characterized as a GREEN finding. Therefore, the violation of the Plant TSs was of very
low safety significance (Green).
Enclosure
36
Enforcement:
Plant TSs 3.8 a.1.b required that during refueling operations, each line that penetrates
containment and which provides a direct air path from containment atmosphere to the
outside atmosphere shall have a closed isolation valve or an operable automatic
isolation valve. Contrary to this, the licensee allowed a surveillance test to defeat
automatic closure features for Reactor Building Isolation such that RBV-1, RBV-2, RBV-
3, and RBV-4 containment isolation valves would not automatically close when required
by a containment high radiation condition. This violation of Plant TSs was of very low
safety significance; therefore, this violation was treated as an NCV consistent with
Section VI.A of the NRC Enforcement Policy (NCV 05000305/2004009-07). Once this
issue was identified, the licensee promptly restored the automatic containment
ventilation isolation capability, initiated procedure changes to prevent this issue from
recurring and entered the issue into the corrective action program (CAP 024107).
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors observed and reviewed the surveillance testing results for the following
surveillances, completing six inspection samples:
Containment Isolation Trip Test;
EDG Blackout Test;
AFW Pumps Full Flow Test;
SI Pumps Full Flow Test;
Control Rod Drop Time Test - Startup Measurements; and
Reactor Coolant System Leak Rate Test.
The inspectors verified that the equipment could perform the intended safety function
and that the surveillance tests satisfied the requirements contained in plant TSs and
licensee procedures. The inspectors reviewed the surveillance tests to verify that the
tests adequately demonstrated operational readiness consistent with plant design and
licensing basis documents, and that the testing acceptance criteria were well
documented and appropriate to the circumstances.
The inspectors observed portions of the test to verify the following attributes:
performance of the test in accordance with prescribed procedures; completion of test
procedure prerequisites; and verification that the test data was complete, appropriately
verified, and met the acceptance criteria of the test. Following the completion of the
tests, when applicable, the inspectors walked down the affected equipment to verify test
equipment removal and to confirm the equipment tested was in an operable condition.
b.
Findings
No findings of significance were identified.
Enclosure
37
1R23
Temporary Plant Modifications (71111.23)
a.
Inspection Scope
The inspectors reviewed the modification documentation and associated 10 CFR 50.59
evaluation for temporary plant modification, completing one inspection sample.
Temporary Change Request (TCR) 04-13, Raise the setpoint of SFP (SFP)
Temperature Switches 12007 and 12012"
The inspectors verified that the temporary modification did not adversely impact other
safety-related equipment and that the modification was controlled in accordance with the
licensees administrative procedures. The inspectors also verified that the modification
did not affect system operability or availability. In addition, the inspectors reviewed CRs
to verify that temporary modification problems were entered into the CAP with the
appropriate significance characterization
b.
Findings
No findings of significance were identified.
1EP6 Drill Evaluation (71114.06)
a.
Inspection Scope
The inspectors observed an Emergency Preparedness Quarterly Drill on
December 14, 2004, completing one emergency planning simulator exercise sample.
The inspectors observed activities in the Control Room Simulator, Emergency
Operations Facility (EOF), Joint Public Information Center (JPIC) and attended the
critique session. The inspectors evaluated the drill performance and determined that
the critique activities appropriately captured weaknesses identified by the inspectors and
verified that deficiencies were entered into the CAP.
b.
Findings
No findings of significance were identified.
Enclosure
38
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1
Review of Licensee Performance Indicators for the Occupational Exposure Cornerstone
a.
Inspection Scope
The inspectors reviewed licensee event reports, corrective action documents, electronic
dosimetry transaction data for radiologically controlled area egress and information
reported on the NRCs web site relative to the licensees occupational exposure control
performance indicator (PI) to determine whether or not the conditions surrounding any
actual or potential PI occurrences had been evaluated, and identified problems had
been entered into the corrective action program for resolution. Performance indicator
data collection and analysis methods were evaluated by the inspectors as described in
Section 4OA1.
This review represented one inspection sample.
b.
Findings
No findings of significance were identified.
.2
Plant Walkdowns and Radiation Work Permit Reviews
a.
Inspection Scope
The inspectors reviewed licensee controls and surveys in the following three
radiologically significant work areas within radiation areas, high radiation areas (HRAs)
and locked high radiation areas in the plant and reviewed work packages which included
associated licensee controls and surveys of these areas to determine if the radiological
controls including area postings and barricades were adequate:
Containment Head Lift Pathway (Containment/Auxiliary Buildings - All Areas);
Containment C Sump Area; and
Containment Seal Table Area.
The inspectors reviewed the radiation work permit (RWP) and associated work
packages which governed work activities and access into these areas and into other
selected high radiation areas to identify the work control instructions and control barriers
that had been specified. Electronic dosimeter alarm set points for both integrated dose
and dose rate were evaluated for conformity with survey indications and plant policy.
Workers were interviewed to verify that they were aware of the actions required when
their electronic dosimeters malfunctioned or alarmed.
Enclosure
39
The inspectors walked down and surveyed (using an NRC survey meter) these areas in
addition to other radiologically significant area boundaries to verify that the prescribed
RWP, procedure, and engineering controls were in place, that licensee surveys and
postings were complete and accurate, and that air samplers were properly located.
During the walkdowns, the inspectors challenged access control boundaries to verify
that high and locked high radiation area access was controlled in compliance with the
licensees procedures, plant TSs and the requirements of 10 CFR 20.1601.
The inspectors reviewed RWPs for the following airborne radioactivity area to verify
barrier integrity and engineering controls performance (e.g., filtered ventilation system
operation) and to determine if there was a potential for individual worker internal
exposures of > 50 millirem committed effective dose equivalent: Containment Seal
Table. Work areas having a history of, or the potential for, airborne transuranics were
evaluated to verify that the licensee had performed surveys to determine the potential
for transuranic isotopes.
The inspectors reviewed the licensees procedures and its methods for the assessment
of internal dose as required by 10 CFR 20.1204, to ensure methodologies were
technically accurate and would include the impact of hard to detect radionuclides such
as pure beta and alpha emitters, if applicable. No worker intakes that resulted in a
committed effective dose equivalent (CEDE) in excess of 50 millirem occurred during
the outage. However, internal dose assessments which resulted in exposures less than
50 milllirem CEDE were selected reviewed by the inspectors for adequacy.
The inspectors reviewed the licensees practices and programmatic controls which
prohibited the temporary storage of highly activated and/or contaminated materials
(non-fuel) within the spent fuel pool attached to cables/lanyards and consequently easily
removable from the pool. Specifically, radiation protection staff were interviewed and a
walkdown of the refuel floor was performed to verify the licensees practices.
These reviews represented six inspection samples.
b.
Findings
No findings of significance were identified.
.3
Problem Identification and Resolution
a.
Inspection Scope
The inspectors reviewed Licensee Event Reports (LERs) and Special Reports, as
applicable, related to the access control program to verify that identified problems were
entered into the corrective action program for resolution. Review of LER 2004-002
related to leak testing of sealed sources was discussed in Section 4OA3.
The inspectors reviewed the licensees corrective action program database for 2004,
and several corrective action reports related to access and exposure controls and three
related to high radiation area radiological incidents (non-Performance Indicator issues
identified by the licensee in high radiation areas < 1R/hr). Staff members were
Enclosure
40
interviewed and corrective action documents were reviewed to verify that follow-up
activities were being conducted in an effective and timely manner commensurate with
their importance to safety and risk based on the following:
Initial problem identification, characterization, and tracking;
Disposition of operability/reportability issues;
Evaluation of safety significance/risk and priority for resolution;
Identification of repetitive problems;
Identification of contributing causes;
Identification and implementation of effective corrective actions; and
Implementation/consideration of risk significant operational experience feedback.
The inspectors evaluated the licensees process for problem identification,
characterization, prioritization, and verified that problems were entered into the
corrective action program and resolved. For repetitive deficiencies and/or significant
individual deficiencies in problem identification and resolution, the inspectors verified
that the licensees self-assessment activities were capable of identifying and addressing
these deficiencies.
The inspectors reviewed licensee documentation packages for all PI or potential PI
events occurring since an occurrence was last reported for an April 15, 2003, event.
The review was conducted to determine if any events involved dose rates > 25 R/hr at
30 centimeters or > 500 R/hr at 1 meter. Unintended exposures > 100 millirem total
effective dose equivalent (or > 5 rem shallow dose equivalent or > 1.5 rem lens dose
equivalent) were evaluated to determine if there were any regulatory overexposures or if
there was a substantial potential for an overexposure. No examples of these type of PI
events occurred.
These reviews represented four inspection samples.
b.
Findings
No findings of significance were identified.
.4
Job-In-Progress Reviews
a.
Inspection Scope
The inspectors observed five jobs that were being performed in radiation areas, high
radiation areas (HRAs) and/or locked high radiation areas to evaluate work activities that
presented the greatest radiological risk to workers. This review was conducted in
conjunction with Inspection Procedure 71121.02, and was documented in
Section 2OS2.4 of this report.
The inspectors also reviewed the licensees procedure and generic practices associated
with dosimetry placement and the use of multiple whole body dosimetry for work in high
radiation areas having significant dose gradients for compliance with the requirements
of 10 CFR 20.1201(c) and applicable industry guidelines.
Enclosure
41
These reviews represented three inspection samples.
b.
Findings
No findings of significance were identified.
.5
High Risk Significant, High Dose Rate HRA, and Very High Radiation Area Controls
a.
Inspection Scope
The inspectors held discussions with the Radiation Protection Manager concerning high
dose rate high radiation area and very high radiation area controls and procedures,
including procedural changes that had occurred since the last inspection, in order to
verify that any procedure modifications did not substantially reduce the effectiveness
and level of worker protection.
The inspectors discussed with radiation protection (RP) supervisors the controls that
were in place for special areas that had the potential to become very high radiation
areas during certain plant operations, to determine if these plant operations required
communication beforehand with the RP group, so as to allow corresponding timely
actions to properly post and control the radiation hazards.
The inspectors conducted plant walk downs to verify the posting and locking of
entrances to selected locked high radiation areas, high dose rate high radiation areas,
and Very High Radiation Areas (VHRAs).
These reviews represented three inspection samples.
b.
Findings
No findings of significance were identified.
.6
Radiation Worker Performance
a.
Inspection Scope
During job performance observations, the inspectors evaluated radiation worker
performance with respect to stated radiation protection work requirements and
evaluated whether workers were aware of the significant radiological conditions in their
workplace, the RWP controls and limits in place, and that their performance had
accounted for the level of radiological hazards present.
The inspectors reviewed three radiological problem reports which found that the cause
of the event was due to radiation worker errors to determine if there was an observable
pattern traceable to a similar cause, and to determine if this perspective matched the
corrective action approach taken by the licensee to resolve the reported problems.
These problems, along with planned and taken corrective actions were discussed with
Radiation Protection Management.
Enclosure
42
These reviews represented two inspection samples.
b.
Findings
No findings of significance were identified.
.7
Radiation Protection Technician Proficiency
a.
Inspection Scope
During job performance observations, the inspectors evaluated radiation protection
technician performance with respect to radiation protection work requirements and
evaluated whether they were aware of the radiological conditions in their workplace, the
RWP controls and limits in place, and if their performance was consistent with their
training and qualifications with respect to the radiological hazards and work activities.
The inspectors reviewed four radiological problem reports which found that the potential
cause of the event was radiation protection technician error to determine if there was an
observable pattern traceable to a similar cause, and to determine if this perspective
matched the corrective action approach taken by the licensee to resolve the identified
problems.
These reviews represented two inspection samples.
b.
Findings
No findings of significance were identified.
2OS2 As Low As Is Reasonably Achievable (ALARA) Planning And Controls (71121.02)
.1
Inspection Planning
a.
Inspection Scope
The inspectors reviewed plant collective outage exposure history, current exposure
trends and ongoing outage activities in order to assess current performance and
exposure challenges. This included determining the plants current 3-year rolling
average for collective exposure in order to help establish resource allocations and to
provide a perspective of significance for any resulting inspection finding assessment.
The inspectors reviewed the outage work scheduled during the inspection period and
associated work activity exposure and time/labor estimates for the following six work
activities which resulted in the highest personnel collective exposures or were otherwise
activities that were conducted in radiologically significant areas:
Bottom Mounted Insulation Replacement;
Outage Containment Scaffolding;
Reactor Vessel Closure Head (RVCH) Disassembly/Reassembly;
Reactor Disassembly/Reassembly;
Enclosure
43
In-Service Inspection; and
Reactor Coolant Pump Seals.
The inspectors determined the site specific trends in collective exposures based on
plant historical exposure and source term data. The inspectors reviewed procedures
associated with maintaining occupational exposures ALARA and assessed those
processes used to estimate and track work activity exposures.
These reviews represented four inspection samples.
b.
Findings
No findings of significance were identified.
.2
Radiological Work Planning
a.
Inspection Scope
The inspectors evaluated the licensees list of work activities ranked by estimated
exposure that were completed during the outage and reviewed the following six work
activities of highest exposure significance:
Bottom Mounted Insulation Removal;
Outage Containment Scaffolding;
RVCH Disassembly/Reassembly;
Reactor Disassembly/Reassembly;
In-Service Inspection; and
Reactor Coolant Pump Seals.
For the activities listed above, the inspectors reviewed the ALARA Plan and associated
RWP, exposure estimates, and exposure mitigation requirements in order to verify that
the licensee had established radiological engineering controls that were based on sound
radiation protection principles in order to achieve occupational exposures that were
ALARA. This also involved determining that the licensee had reasonably grouped the
radiological work into work activities, based on historical precedence, industry norms,
and/or special circumstances.
The inspectors compared the exposure results achieved for its combined refueling and
reactor head replacement outage, including the dose rate reductions and person-rem
expended, with the dose projected in the licensees ALARA planning for these work
activities. Reasons for inconsistencies between intended (projected) and actual work
activity doses were evaluated to determine if the activities were planned adequately and
to ensure the licensee identified any work interface/planning deficiencies. Those jobs
that accrued greater than 5 rem and that exceeded their respective initial dose
estimates by greater than 50 percent were investigated by the inspectors. The
investigations were conducted to determine if deficiencies with radiological planning or
with work execution contributed significantly to the dose overages which the licensee
should reasonably have identified and prevented.
Enclosure
44
The interfaces between radiation protection, plant engineering and scheduling groups
were reviewed to varying degrees to identify potential interface problems. The
integration of ALARA requirements into work procedure and RWP documents was
evaluated to verify that the licensees radiological job planning would reduce dose.
The inspectors compared the person-hour estimates provided by maintenance planning
and/or craft groups to the radiation protection ALARA staff with the actual work activity
time expenditures in order to evaluate the accuracy of these time estimates.
The inspectors evaluated if work activity planning included consideration of the
benefits of dose rate reduction activities such as shielding provided by water filled
components/piping, system flushing and hydrolazing and sequencing of scaffold and
shielding installation/removal in order to maximize dose reduction.
The licensees work in progress reports were reviewed for those outage jobs that
accrued collective exposures between 50 and 100 percent of that projected to verify that
the licensee could identify problems and address them as work progressed. Jobs that
accrued greater than one rem and exceed 125 percent of the projected doses were also
reviewed to ensure work was suspended, if warranted, and identified problems were
entered into the corrective action program consistent with the licensees procedure.
Additionally, post job reviews being developed during the latter stages of the inspection
period were discussed with the licensees ALARA staff to determine the scope and
breadth of the deficiencies that were identified and the status of documenting outage
lessons learned.
These reviews represented eight inspection samples.
b.
Findings
No findings of significance were identified.
.3
Verification of Dose Estimates and Exposure Tracking Systems
a.
Inspection Scope
The inspectors reviewed the licensees assumptions and basis for its collective outage
exposure estimate, and evaluated the methodology and practices for projecting work
activity specific exposures. This included evaluating both dose rate and time/labor
estimates for adequacy compared to historical station specific or industry data.
The inspectors reviewed the licensees process for adjusting outage exposure estimates
when unexpected changes in scope, emergent work or other unanticipated problems
were encountered which significantly impacted worker exposures. This included
determining that adjustments to estimated exposure (intended dose) were based on
radiation protection and ALARA principles and not adjusted to account for failures to
plan or control the work. The frequency of these adjustments was reviewed to evaluate
the adequacy of the original ALARA planning process.
Enclosure
45
The licensees exposure tracking system was evaluated to determine whether the level
of exposure tracking detail, exposure report timeliness, and exposure report distribution
was sufficient to support control of collective exposures. RWPs were reviewed to
determine if they covered too many work activities to allow work activity specific
exposure trends to be detected and controlled. During the conduct of exposure
significant work, the inspectors evaluated if licensee management was aware of the
exposure status of the work and would intervene if exposure trends increased
significantly beyond exposure estimates.
These reviews represented three inspection samples.
b.
Findings
No findings of significance were identified.
.4
Job Site Inspections and ALARA Control
a.
Inspection Scope
The inspectors observed the following five jobs that were being performed in radiation
areas, airborne radioactivity areas, or high/locked high radiation areas to evaluate those
work activities that presented the greatest radiological risk to workers:
Bottom Mounted Insulation Replacement;
Outage Containment Scaffolding;
RVCH Disassembly;
In-Service Inspection & Support; and
Reactor Coolant Pump Seals.
The licensees use of ALARA controls for these work activities was evaluated using the
following:
The licensees use of engineering controls to achieve dose reductions was
evaluated to verify that procedures and controls were consistent with the
licensees ALARA reviews, that sufficient shielding of radiation sources was
provided for, and that the dose expended to install/remove the shielding did not
exceed the dose reduction benefits afforded by the shielding.
Job sites were observed to determine if workers were utilizing the low dose waiting
areas and were effective in maintaining their doses ALARA by moving to the low dose
waiting area when subjected to temporary work delays.
The inspectors attended work briefings and observed ongoing work activities to
determine if workers received appropriate on-the-job supervision to ensure the ALARA
requirements are met. This included verification that the first-line job supervisor ensured
that the work activity was conducted in a dose efficient manner by minimizing work crew
size, ensuring that workers were properly trained, and that proper tools and equipment
were available when the job started.
Enclosure
46
The inspectors reviewed the exposures of individuals involved in the Bottom Mounted
Insulation Replacement Project. Worker exposures were reviewed to determine
whether any significant variations were the result of poor ALARA work practices.
These reviews represented four inspection samples.
b.
Findings
No findings of significance were identified.
.5
Source Term Reduction and Control
a.
Inspection Scope
The inspectors reviewed licensee records to understand historical trends and current
status of plant source terms. The inspectors discussed the plants source term with
ALARA staff to determine if the licensee had developed an adequate understanding of
the input mechanisms and the methodologies and practices necessary to achieve
reductions in source term. The inspectors discussed the water chemistry control
initiatives implemented during the cool-down for the outage and its impact on source
term reduction compared to industry practices.
While the licensee did not have a formal source term control strategy in place, source
term reduction initiatives typically implemented by the licensee were discussed with
ALARA staff as were plans for the development of a long term reduction plan. The
inspectors determined if specific sources had been identified by the licensee for
exposure reduction initiatives and that priorities were being considered for the
implementation of these actions.
These reviews represented two inspection samples.
b.
Findings
No findings of significance were identified.
.6
Radiation Worker Performance
a.
Inspection Scope
Radiation worker and radiation protection technician performance was observed during
work activities being performed in radiation areas, airborne radioactivity areas, and high
radiation areas that presented the greatest radiological risk to workers. The inspectors
evaluated whether workers demonstrated the ALARA philosophy in practice by being
familiar with the work activity scope and tools to be used, by utilizing ALARA low dose
waiting areas, and that they had knowledge of the radiological conditions and adhered
to the ALARA requirements for the work activity. Also, radiation worker training and skill
levels were reviewed to determine if they were sufficient relative to the radiological
hazards and the work involved.
This review represented one inspection sample.
Enclosure
47
b.
Findings
No findings of significance were identified.
.7
Monitoring of Declared Pregnant Women and Dose to Embryo/Fetus
a.
Inspection Scope
The inspectors reviewed the licensees monitoring methods and procedures,
exposure controls, and the information provided to declared pregnant women to
determine if an adequate program had been implemented to limit embryo/fetal dose.
The inspectors also reviewed the pregnancy declaration and radiation exposure results
for several individuals that declared their pregnancy to the licensee in 2003 through
December 2004, to verify compliance with the requirements of 10 CFR 20.1208
and 20.2106.
This review represented one inspection sample.
b.
Findings
No findings of significance were identified.
.8
Problem Identification and Resolution
a.
Inspection Scope
The inspectors reviewed the licensees self-assessments, audits, and Special Reports
related to the ALARA program since the last inspection to determine if the licensees
overall audit programs scope and frequency for all applicable areas under the
Occupational Cornerstone met the requirements of 10 CFR 20.1101(c).
Several corrective action reports related to the ALARA program were reviewed and staff
members were interviewed to verify that follow-up activities had been conducted in an
effective and timely manner commensurate with their importance to safety and risk
using the following criteria:
Initial problem identification, characterization, and tracking;
Disposition of operability/reportability issues;
Evaluation of safety significance/risk and priority for resolution;
Identification of repetitive problems;
Identification of contributing causes;
Identification and implementation of effective corrective actions; and
Implementation/consideration of risk significant operational experience feedback.
The inspectors reviewed and/or discussed with ALARA staff its ongoing post-job
reviews of outage exposure performance. The inspectors determined whether dose
performance issues were being adequately characterized, prioritized and resolution was
being sought through the corrective action process.
Enclosure
48
The licensees corrective action program was also reviewed to determine if repetitive
deficiencies and/or significant individual deficiencies in problem identification and
resolution had been addressed.
These reviews represented four inspection samples.
b.
Findings
No findings of significance were identified.
Cornerstone: Public Radiation Safety
2PS2 Radioactive Material Processing and Transportation (71122.02)
.1
Waste Characterization and Classification of the Old RVCH
a.
Inspection Scope
The inspectors reviewed the licensees waste stream radiochemical sample analysis
results, radiological surveys, and shielding and source term calculations that were used
to develop the Class A waste characterization of the old RVCH. These reviews were
conducted to verify that the licensees characterization assured compliance with
10 CFR 61.55 and 10 CFR 61.56, as required by Appendix G of 10 CFR 20.
Additionally, the inspectors reviewed the licensees calculations used to determine the
Department of Transportation sub-typing for the shipment of the RVCH, so as to verify
the Low Specific Activity (LSA)-II sub-typing complied with 49 CFR 172, 173, and 177.
No samples under the baseline inspection procedure were completed by this review.
b.
Findings
No findings of significance were identified.
.2
Shipment Preparation and Shipping Records for the Old RVCH
a.
Inspection Scope
The inspectors reviewed the licensees procedures and documentation (including
photographs) for shipment packaging, surveying, labeling, marking, placarding, vehicle
checks, emergency instructions, disposal manifest, shipping papers provided to the
driver, and licensee verification of shipment readiness for the shipment of the old RVCH
to the low-level radioactive waste disposal facility, Envirocare of Utah, Inc., in Clive,
Utah. The inspectors selectively verified that the requirements of 10 CFR 20 and 61
and those of the Department of Transportation in 49 CFR 170-189 were met for the
RVCH shipment to Envirocare.
No samples under the baseline inspection procedure were completed by this review.
Enclosure
49
b.
Findings
No findings of significance were identified.
2PS3 Radioactive Material Control (71122.03)
1.
Temporary Storage of the Old RVCH
a.
Inspection Scope
The inspectors reviewed licensee controls and surveys of the temporary storage location
of the old RVCH in Containment (prior to packaging and shipment), to determine if
radiological controls including surveys, postings and barricades were acceptable.
Additionally, the inspectors evaluated the licensees contamination and engineering
controls in place around the temporary storage location of the old RVCH while the
containment equipment hatch was open to verify that any contamination on the old
RVCH did not contribute to an unmonitored airborne effluent or liquid radioactive
material release pathway from the plant.
No samples under the baseline inspection procedure are completed by this review.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
.1
Reactor Safety Strategic Area
a.
Inspection Scope
The inspectors reviewed the licensee submittals for the following PIs, completing two PI
verification inspection samples:
Safety System Functional Failure; and
High Pressure Injection Unavailability;
The inspectors used PI guidance and definitions contained in Nuclear Energy Institute
Document 99-02, Revision 2, Regulatory Assessment PI Guideline, to verify the
accuracy of the PI data for the first, second and third quarters 2004. The inspectors
review included, but was not limited to, conditions and data from logs, CRs, and
calculations for each PI specified. The inspectors also reviewed CRs to verify that
licensee personnel identified issues at an appropriate threshold and entered them into
the CAP in accordance with station CA procedures.
Enclosure
50
b.
Findings
No findings of significance were identified.
.2
Radiation Safety Strategic Area
a.
Inspection Scope
The inspectors sampled licensee submittals for the performance indicator (PI) listed
below for the period May 2003 through mid-December 2004. To verify the accuracy of
the PI data reported during that period, PI definitions and guidance contained in
Revision 2 of Nuclear Energy Institute Document 99-02, Regulatory Assessment
Performance Indicator Guideline, were used. The following PI was reviewed:
Occupational Exposure Control Effectiveness
For the time period reviewed, no reportable occurrences were identified by the licensee.
(A TS occurrence involving the unauthorized removal of a flashing red light that was
used to control access into a LHRA was identified by the licensee on April 15, 2003, and
was reported as required for the second quarter of 2003). To assess the adequacy of
the licensees PI data collection and analyses, the inspectors discussed with radiation
protection staff the scope and breadth of its PI data review and the results of those
reviews. The inspectors independently reviewed selected electronic dosimetry dose
alarm reports (radiologically controlled area electronic dosimetry egress transactions),
the personnel contamination report for the outage, dose assignments for intakes, and
the licensees CAP database along with individual CAPs generated during the period
reviewed to verify there were no unrecognized occurrences. Additionally, as discussed
in Sections 2OS1.2 and 2OS1.5, the inspectors walked down the boundaries of selected
locked high radiation areas to verify the adequacy of postings and access control
physical barriers.
These reviews represented one inspection sample.
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 issues were
entered into the licensees corrective action program at an appropriate threshold, that
adequate attention was given to timely CAs, and that adverse trends were identified and
addressed. The inspectors also reviewed all CAPs written by licensee personnel during
the inspection quarter. Minor issues entered into the licensees CAP program as a
Enclosure
51
result of inspectors observations were included in the list of documents in the
Attachment in the section entitled Condition Reports Initiated for NRC Identified
Issues.
b.
Findings
No findings of significance were identified.
.2
Annual Sample Review
a.
Inspection Scope:
The inspectors selected Condition Report CAP 021915, "Hydrogen and Propane Gas
Lines Are Not Identified in the Fire Strategies," for an annual sample review of the
licensees problem identification and resolution program. This constitutes one annual
review inspection procedure sample.
b.
Findings
Introduction:
The inspectors identified a NCV of License Condition fire protection requirements having
very low safety significance (Green) for not identifying pertinent information, such as the
presence of compressed flammable gas cylinders, on fire area strategies.
Description:
The failure to identify hydrogen and propane gas lines passing trough a fire
zone in a pre-fire plan (PFP) had been identified by the NRC as part of a triennial
fire protection inspection (documented in Section 1R05.10.b.2 of Inspection
Report 05000305/2004005). The licensee entered this issue in their corrective action
program under CAP 021915 at that time and subsequently revised one PFP to note the
existence of the hydrogen and propane lines. Based on discussions with fire protection
personnel, the inspectors learned that no other PFPs were reviewed to verify that they
included pertinent information or determined the extent of condition.
During this inspection, the inspectors identified that PFP-17, as of October 22, 2004,
did not identify that there were combustible gas cylinders within Fire Zone 23B. On
October 22, 2004, and December 1, 2004, the inspectors observed a number of
compressed gas cylinders with combustible concentrations of flammable gas. The gas
cylinders included a propane cylinder and a number cylinders containing mixtures of
hydrogen and nitrogen. These compressed flammable gas cylinders were located near
doors 196 and 255 on the 586 foot elevation of Fire Zone 23B within the auxiliary
building. However, the layout diagram for PFP-17, the applicable fire area strategy for
the 586 foot elevation of Fire Zone 23B, only identified that compressed gases (versus
compressed flammable gases) were stored in this area of the auxiliary building. The
text for PFP-17 identified lubricating oil in pumps as the only flammable or combustible
gas or liquid. PFP-17 did not mention the presence of compressed hydrogen and
propane gases as being present. In addition, the inspectors identified a number of
Enclosure
52
discrepancies between the hazards identified in the fire zone summaries of the Fire
Protection Program Analysis versus what had been identified in the applicable PFP for
the fire zone.
Analysis:
In accordance with IMC 0612, "Power Reactor Inspection Reports," dated January 14,
2004, the inspectors determined that the issue of not maintaining acceptable fire
pre-plans was a performance deficiency. This performance deficiency was determined
to be greater than minor because it affected the mitigating systems cornerstone attribute
of protection against external factors (fire). Specifically, the failure to provide adequate
warnings and guidance relating to hazards associated with hydrogen and propane
compressed gas cylinders in fire strategies could adversely impact fire fighting
strategies used by the fire brigade in fighting a fire. In accordance with IMC 0609,
Appendix AProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix A" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., "Significance Determination of Reactor Inspection Findings for At-Power
Situations," dated, March 18, 2002, the inspectors performed a SDP Phase 1 screening
and determined that the finding affected fire protection defense-in-depth. As such, the
inspectors determined that a Phase 2 analysis in accordance with IMC 0609,
Appendix FProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix F" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., "Fire Protection SDP," dated May 28, 2004, was required. As discussed by
IMC 0308, Attachment 3, Appendix F, "Technical Basis, Fire Protection Significance
Determination Process (IMC 609 App. F) At Power Operations," the current significance
determination process did not address findings which affected the performance of the
fire brigade. As such, the inspectors used judgement based on experience to determine
the safety significance of the issue. The inspectors determined that the issue was of
very low safety significance (Green) due to extensive training provided to fire brigade
members to deal with unexpected contingencies.
Enforcement:
KNPP License Condition 2.C(3), required, in part, that NMC implement and maintain in
effect all provisions of the approved fire protection program as described in the KNPP
Fire Plan. Section 10.3, "Fire Area Strategies," of the KNPP Fire Protection Program
Plan specified that fire area strategies were documents which provided the fire brigade
pertinent information on a given plant area to help the brigade to be better prepared for
fire fighting within that area. PFP-17 was the fire area strategy for the 586 foot elevation
of Fire Zone AX-23B. Contrary to the above, PFP-17 did not contain pertinent
information on a given plant area, the 586 foot elevation of Fire Zone 23B, in that the fire
area strategy did not identify that compressed gas cylinders in the area contained
flammable gases. Once this issue was identified, the licensee entered the issue into
their corrective action program under CAP 023479. The licensee subsequently
informed the inspectors that PFP-17 had been specifically revised to note the presence
of the compressed flammable gas cylinders. Because this violation was of very low
safety significance and it was entered into the licensees corrective action program, this
violation is being treated as a NCV, consistent with Section VI.A of the NRC
Enforcement Policy (NCV 05000305/2004009-08).
Enclosure
53
4OA3 Event Followup (71153)
.1
(Closed) Licensee Event Report (LER) 50-305/2004-003-00: Control Room Boundary
Door Found Ajar - Accident Analysis Assumptions Impacted - Personnel Error
On August 12, 2004, while the plant was operating at full power, on-shift plant
Operations department personnel, during a normal operating equipment tour,
discovered a control room emergency zone barrier door (Door #152) not fully closed.
Full closure of this door is required to ensure operability of the Control Room Post
Accident Recirculation system. The underlying causes of the failure were considered to
be deficiencies in the plants overall barrier control program. This finding was more than
minor because, if left uncorrected, the issue would have become a more significant
safety concern. In addition, it affected the Mitigating Systems attributes of equipment
performance reliability and the Mitigating Systems Cornerstone objective of insuring the
reliability of systems. The inspectors evaluated the finding using IMC 0609, Appendix A,
Phase 1 screening. Phase 1 screening required that this finding be evaluated using
Phase 3. The Phase 3 result identified this finding as Green due to the very short
duration in which the situation associated with this finding existed. Therefore, the
finding was determined to be of very low safety significance (Green). This licensee-
identified finding involved a violation of 10 CFR 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings. The enforcement aspects of the violation are
discussed in Section 4OA7. This LER is closed.
.2
(Closed) LER 50-305/2004-002-00: Missed TS Surveillance for Leak Testing In-Core
Detectors Prior to Use or Transfer, Due Inadequate Procedural Guidance
On July 21, 2004, in response to an Operating Experience Notice (CAP 019783) review,
NMC Nuclear Oversight personnel discovered that TS 4.13 requirement for in-core
detectors containing byproduct materials greater than 0.1 microcuries was not met
for 13 detectors that were transferred to another licensee. Technical Specification 4.13
required leak test detectors that were in storage prior to removal for use or prior to
shipment to other licensed entities. The licensee identified that the root cause for the
missed leak test was the failure of the existing procedures to properly control required
TS requirements and the inadequate degree of instructional details in the procedure
RE 05, In-core Instrumentation Periodic Hardware Maintenance, and RE-24, Special
Nuclear Material Control. Corrective Actions prescribed by the licensee included:
present and discuss the issue with the radiation protection staff;
revise the two procedures (RE-05 and RE-24);
contact the licensee that received the in-core detectors from Kewaunee and
request that they perform a leak test on those in-core detectors received from
Kewaunee.
The subsequent leak tests did not identify any leaking detectors. The failure to leak test
the in-core detectors prior to transfer constituted a violation of minor significance that
was not subject to enforcement action in accordance with Section IV of the NRCs
Enclosure
54
Enforcement Policy. The LER was reviewed by the inspectors and no findings of
significance were identified. The licensee documented the failure to leak test the
detectors in CAP 021686. This LER is closed.
4OA4 Cross-Cutting Aspects of Findings
.1
A finding described in Section 1R05.1.b.1 of this report was related to the cross-cutting
area of problem identification and resolution, related to the performance characteristic of
corrective actions. Specifically, the licensees corrective actions were ineffective in that
the NRC had previously identified incidents involving unauthorized storage of
combustible materials above shelves in the materials storage working area and nearby.
The inspectors identified additional examples during this inspection.
.2
A finding described in Section 4OA5.2.c.1 of this report was related to the cross-cutting
area of problem identification and resolution, related to the performance characteristic of
corrective actions. Specifically, the licensee failed to take corrective actions for
conditions adverse to quality related to the sump screen openings.
4OA5 Other Activities
.1
Reactor Pressure Vessel (RPV) Lower Head Penetration Nozzles (TI 2515/152)
a.
Inspection Scope
The inspectors performed a review of licensee activities in response to NRC
Bulletin 2003-02, Leakage from Reactor Pressure Vessel Lower Head Penetrations and
Reactor Coolant Pressure Boundary Integrity, in accordance with NRC Temporary
Instruction (TI) 2515/152, Reactor Pressure Vessel Lower Head Penetration Nozzles.
The reviewed the licensees procedures, equipment, and personnel used for RPV lower
head penetration examinations to confirm that the licensee met commitments
associated with Bulletin 2003-02. The results of the inspectors review included
documentation of observations and conclusions in response to the questions identified
in TI 2515/152.
b.
Findings:
Based upon a bare metal visual (BMV) examination of the lower head, the licensee did
not identify evidence of reactor coolant system leakage near the instrument nozzle
penetrations. Several areas of white streaking and rust colored residue were observed
on the bare metal of the reactor vessel bottom head located around the 36 bottom
mounted instrumentation. The licensee believed that these stained areas were caused
by liquid which had rundown from reactor vessel cavity leakage.
Evaluation of Inspection Requirements
In accordance with requirements of TI 2515/152, the inspectors evaluated and
answered the following questions:
Enclosure
55
For each of the examinations methods used during the outage, was the examination:
1.
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 RPV lower
head penetration interface and RPV lower head surface for leakage or boric
acid deposits with knowledgeable staff members certified to Level III and Level II
as VT-3 examiners. One examiner was a licensee staff member certified to
licensee procedure FP-PE-NDE-3, Written Practice For Qualification And
Certification For NDE Personnel, and GNP-01.05.05, Revision A, Written
Practice for Qualification and Certification of Kewaunee Nuclear Power Plant
Personnel in Visual Examination Methods (VT); the other was a licensee
contractor certified to the contractors procedure QA-45 Revision 1, Qualification
and Certification of NDE and Visual Examination Personnel per ASME
Section XI, 2000 Addendum. These qualification and certification procedures
were consistent with the requirements of industry standard ANSI/ANST CP-189,
Standard for Qualification and Certification of Nondestructive Testing
Personnel, and/or ASNT-SNT-TC-1A-1984. Additionally, each of the VT-2
examination personnel had reviewed photographs of the boric acid deposits
indicative of penetration leakage found at the South Texas Nuclear Power Plant.
2.
Performed in accordance with demonstrated procedures?
Yes. The licensee performed a bare metal inspection of the lower head in
accordance with procedure NEP 15.05, Revision A, Visual Examination for
Inservice Inspection. The licensee considered this procedure to be
demonstrated because their examination personnel could resolve the lower case
alpha numeric characters 0.105 inches in height at a maximum of 4 feet under
existing lighting to meet Code VT-3 inspection criterion. In addition, the licensee
had specific guidance or reference, written paper, Sampling and Analysis
Guidance for Deposits Found on Reactor Pressure Vessels at Various
Locations, for when and how to take samples of deposits if any had been
identified near the interface of lower head penetrations and what analysis would
be performed to determine the source of deposits identified.
However, the inspectors identified parameters that could impact the
quality/effectiveness of the inspection and were not controlled by the procedure.
Specifically, the procedure did not provide:
specific guidance to identify recordable indications of corrosion or
wastage if it had been present on the lower head. Note that no
significant corrosion or wastage was present based upon the NRC
inspectors inspection of the head; and
useful orientation and penetration numbering figure/schematic for the
BMI penetrations.
The inspectors performed an independent direct bare metal visual examination
for most of the 36 lower head penetration nozzles. This inspection was
Enclosure
56
conducted from a platform under the vessel head and the inspectors determined
that each penetration was readily accessible such that the visual examination
could be performed within a few inches of each penetration location.
Additionally, the inspectors reviewed a sample of licensee photographs taken at
each penetration nozzle. Based upon this inspection and interviews with
inspection staff, the inspectors did not identify any concerns associated with
implementation of the visual inspection procedure for the lower head.
3.
Able to identify, disposition, and resolve deficiencies?
Yes. Several areas of white streaking and rust colored residue were observed
on the bare metal of the reactor vessel bottom head located around the 36
bottom mounted instrumentation penetrations. The licensee believed that these
stained areas were caused by rundown from liquid sources above the bottom of
the vessel. Chemistry analysis was performed and the results indicated that the
white streaking was attributed to reactor vessel cavity leakage. Based upon the
visual examination, the licensee did not identify any penetrations with boric acid
deposits indicative of coolant leakage.
4.
Capable of identifying pressure boundary leakage as described in the bulletin
and/or RPV lower head corrosion?
Yes. The inspectors performed a direct visual inspection of portions of the 36
lower VHPs. Based on this examination, and interviews with licensee examiners,
the inspectors concluded that the visual examination was capable of detecting
deposits indicative of pressure boundary leakage as described in the bulletin.
5.
Could small boric acid deposits representing reactor coolant system leakage as
described in Bulletin 2003-02 be identified and characterized, if present, by the
visual examination method used?
Yes. If small boric acid deposits characteristic/indicative of leakage had existed,
the licensees examination would have identified these. However, no boric acid
deposits indicative of leakage were identified.
6.
How was the visual inspection conducted (e.g., with video camera or direct visual
by examination personnel)?
Licensee personnel conducted a direct visual examination of each of the lower
head penetration nozzles. This examination included a bare metal visual
examination of the lower head up to the transition to the vertical vessel shell wall.
In addition, photographs were taken of all the instrumentation penetrations and
the surface area of the reactor vessel lower head.
7.
How complete was the coverage (e.g., 360 degrees around the circumference of
all the nozzles)?
The examination coverage included a 360 degree unobstructed examination of
each of the 36 lower head penetration nozzles at the interface of the vessel
Enclosure
57
head. The entire lower head was accessible for a visual inspection to identify
corrosion and wastage.
8.
What was the physical condition of the RPV lower head (e.g., debris, insulation,
dirt, deposits from any source, physical layout, viewing obstructions)? Did it
appear that there are any boric acid deposits at the interface between the vessel
and the penetrations?
The Kewaunee reactor pressure vessel was installed with mirror-type insulation
at the lower RPV dome. This insulation generally conformed to the contour of
the lower RPV dome but had a gap of about 1 - 3 inches between the RPV
surface and insulation. Each BMI penetration had a slight gap that varied in size
and was normally covered by metal flashing. The licensee intended to install a
revised lower head insulation structure with a tub type configuration (e.g.,
horizontal insulation floor with vertical walls). This revised insulation design
provided for access doors in the vertical and horizontal walls to allow access for
future bare metal head inspections. For this inspection, all of the lower insulation
had been removed to provide unobstructed access to the BMI penetrations. This
inspection was conducted from a platform under the vessel head and the
inspectors determined that each penetration was readily accessible such that the
visual examination could be performed within a few inches of each penetration
location. A specific description of the RPV lower head is contained in the answer
to Question 3 above. Based upon the inspectors inspection, they did not identify
any boric acid deposits at the interface between the vessel and the penetrations .
9.
What material deficiencies (i.e., crack, corrosion, etc.) were identified that
required repair?
None. No boric acid deposits indicative of leakage were identified and thus no
repairs were required.
10.
What, if any, impediments to effective examinations, for each of the applied
nondestructive examination method, were identified (e.g., insulation,
instrumentation, nozzle distortion)?
The direct visual examination required access to the RPV lower head and
instrument nozzle penetrations by climbing down a ladder, into the keyway (a
sump area under the vessel). This area was a confined space, a high radiation
area, and was congested by the instrument tubes and their supports. Scaffold
had been installed to support removal of the lower insulation and to allow access
for direct inspection of the BMI penetrations. With the insulation removed, each
penetration was accessible from this platform for direct visual inspection.
11.
Did the licensee perform appropriate follow-on examinations for indications of
boric acid leaks from pressure-retaining components above the RPV lower
head?
Enclosure
58
As noted in the answer to Question 3 above, the licensee did identify white
streaking which they attributed to reactivity cavity seal leakage. However, as
noted in the answer to Question 12 below, this leakage was no longer active.
12.
Did the licensee take any chemical samples of the deposits? What type of
chemical analysis was performed (e.g., Fourier Transform Infrared(FTIR)), what
constituents were looked for (e.g., boron, lithium, specific isotopes), and what
were the licensees criteria for determining any boric acid deposits were not from
RCS leakage (e.g., Li-7, ratio of specific isotopes, etc.)?
Yes. The licensee collected samples of deposits from five locations on the
reactor lower head. A control swipe was also taken from an area on the head
that had no indications of boric acid or other noticeable deposits. All samples
were counted for qualitative isotopic analysis. Sampling and analysis
methodologies were based on a document prepared by Electric Power Research
Institute (EPRI) and member utilities titled, Sampling and Analysis Guidance for
Deposits Found on Reactor Pressure Vessels at Various Locations, dated
September 2003. Based on the observations from the Gamma Isotopic
analyses, a lack of short-lived isotopes indicated no active leakage.
Furthermore, there were only two isotopes present, Co-60 and Cs-137. Using
the radionuclide ratio of Co-60/Cs-137 as a method to identify the leakage, all
the samples ratios as well as the typical ratio in the Refueling Water Storage
Tank (RWST) were whole numbers equal to 2.6 or greater; the typical ratio for
Reactor Coolant System (RCS) ratio is 0.6. The last notable observation from
the isotopic data was that the results of the residue and swipe samples #1 - 4
were not noticeably different than swipe #5, the control swipe taken from a
residue free area of the vessel. Therefore, the licensee concluded that the white
streaking was attributable to reactivity cavity seal leakage that was no long
active.
13.
Is the licensee planning to do any cleaning of the head?
Yes. The licensee planned to clean the head with demineralized water and
scotch-bright pads.
14.
What are the licensees conclusions regarding the origin of any deposits present
and what is the licensees rationale for the conclusions?
The licensee concluded that the residue was not from an active leak, but that
these stained areas were caused by liquid which had rundown from reactor
vessel cavity leakage. The licensees rationale for this was based on the results
obtained from isotopic analysis of the samples obtained.
.2
Reactor Containment Sump Blockage (TI 2515/153)
a.
Inspection Scope
The inspectors performed a preliminary review of licensee activities in response to NRC
Bulletin 2003-01, "Potential Impact of Debris Blockage on Emergency Sump
Enclosure
59
Recirculation at Pressurized Water Reactors (PWRs)," in accordance with NRC
Temporary Instruction (TI) 2515/153, "Reactor Containment Sump Blockage (NRC
Bulletin 2003-01)," dated October 3, 2003. The inspectors reviewed the licensees
completed and proposed compensatory measures submitted in accordance with Bulletin
2003-01, Option 2, which were contained in the licensees correspondence to the NRC
dated August 7, 2003, and May 17, 2004. The inspectors verified that the
compensatory measures committed to were implemented, or were planned and
scheduled for implementation consistent with the licensees response. In accordance
with TI 2515/153 Section 04.02.b, the inspectors discussed the licensees response with
the NRR Project Manager since a NRR acknowledgment letter had not been issued for
the licensees response at the time of the inspection.
Visual inspections of the containment sumps, sump screens and flow paths were
performed by the inspectors during the refueling outage. The inspectors also walked
down containment to verify that the condition of the containment coatings, piping
insulation, post Loss-of-Coolant-Accident (LOCA) drainage paths, and Emergency Core
Cooling System (ECCS) recirculation sumps were consistent with the conditions
reported and documented by the licensee. The inspectors interviewed operating and
engineering personnel and reviewed training records, procedures for foreign material
control and containment inspection, and the results of licensee containment coating and
debris generation inspections.
b.
Findings:
The following information is provided as required by Section 5, Reporting
Requirements, of TI 2515/153.
During this inspection period Kewaunee completed a refueling outage (Refueling
Outage Number R27) and subsequently returned to power. In addition, the inspectors
verified the licensee had performed similar inspections in the Refueling Outage which
occurred 18 months prior in the Spring of 2003 (Refueling Outage Number R26).
During the refueling outages, containment walkdowns were conducted by the licensee to
further quantify and in some cases remove potential debris sources. During the
walkdowns, the inspectors verified that the licensees current quantification of potential
debris sources was accurate. The licensees walkdown also checked for gaps in the
sump screen and for major obstructions in the containment upstream of the sump. The
inspectors did identify two issues related to the containment sump during this inspection,
which were discussed further in Sections 4OA5.2.c.1 and 4OA5.1.c.2 of this report.
Licensee engineers stated that advance long term preparations were being made to
expedite the performance of sump-related modifications, in case the licensee
determined modifications were necessary after performing the sump evaluation. At the
time of the inspection, these actions included the initiation of additional engineering
evaluations by the licensee.
Finally, the inspectors verified that the compensatory measures committed to by the
licensee in correspondence to the NRC dated August 7, 2003, and May 17, 2004, were
either implemented or scheduled for implementation in accordance with the timetables
committed to by the licensee. The inspectors determined that the licensee met the
Enclosure
60
current commitments, with one minor exception. Commitment 1 in the licensees
August 7, 2003, submittal stated, in part, that NMC would develop and implement
training on sump clogging by December 19, 2003, as a compensatory measure. The
licensees correspondence further clarified that a sump clogging training module would
be developed and administered to license operators, auxiliary operators, and
Emergency Directors. The sump clogging training was comprised of seven topics,
which included a review of the importance of aggressively cooling the reactor coolant
system in order to transition to shutdown cooling as soon as possible to avoid
recirculation cooling, and a review of the content and implementation of the severe
accident management guidelines, including actions available to respond to sump
clogging.
During a review of the training module and records, the inspectors identified that the
sump clogging training module given to the licensed operators covered five topics, but
did not address the importance of aggressive cooling and did not review the content and
implementation of the severe accident management guidelines. In addition, the
inspectors noted that the sump clogging training had not been given to the auxiliary
operators and Emergency Directors. Finally, the inspectors identified that the licensee
had not established a program to ensure that the sump clogging training was given to
new licensed operators, auxiliary operators and Emergency Directors while the
compensatory measures remained in effect, until the licensee completed the final sump
analysis. The inspectors determined the failure to meet this commitment was of minor
significance, and the licensee initiated Condition Report CAP 023615. In addition, the
licensee conducted the training which was committed to prior to the startup of the plant
from Refueling Outage 27.
b.1
Non-conforming Condition on the Safety-Related Containment Sump
Introduction:
A finding of very low safety significance (Green) was identified by the inspectors for a
violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions. During a review
of the licensing and design basis of the containment sump screens, the inspectors noted
that the screen size allowed particles greater than 1/8 inch to enter the sump, when the
original licensing basis of the screens was to prevent any particles greater than 1/8 inch
from entering the sump. The inspectors subsequently determined this issue was
identified in the licensees corrective action program; however, adequate corrective
actions were not taken to correct this condition adverse to quality.
Description:
The inspectors performed an inspection of the licensees conical sump screens and
noted that the sump screen opening size on both screens was approximately 1/8 inch by
15/32-inch. The inspectors subsequently reviewed the design and licensing basis of the
sump screens to verify the original screens were properly constructed in accordance
with the design and licensing basis.
On September 23, 1971, the Atomic Energy Commission (AEC) issued a request for
additional information related to the review of the Final Safety Analysis Report (FSAR)
Enclosure
61
for the Kewaunee plant. Question 6.19 in the request from the AEC to Wisconsin Public
Service (WPS) Corporation stated, Provide a description of the screens installed for the
containment sumps, including the size of foreign matter that will be precluded from
entering the recirculation system. Wisconsin Public Service Corporation responded to
the AECs Question 6.19 in a docketed letter dated December 15, 1971, which
transmitted FSAR Amendment 13, and annotated that the response to Question 6.19
was located on Page 6.2-9. Section 6.2.2, Recirculation Phase, stated, Foreign
matter is prevented from entering the recirculation system by two screens mounted over
the sump inlet. These screens are conical in shape, manufactured of Johnson Screen
material and sized to prevent any particles larger than 1/8 inch from entering the sump.
Based on licensee documentation for the purchase of the safety related screens in May
1973, the screens were ordered with a 1/8 inch slot opening and support rods placed on
5/8 inch center which created a 1/8 inch by 15/32 inch screen opening. Therefore, at
the time of installation in 1973, the two conical sump screens would have allowed
particles larger than 1/8 inch to enter the sump. The inspectors determined that no
modifications were made to the sump since the time of original installation, and no
correspondence was submitted to the AEC discussing the change in the size of particle
which could enter the sump.
The inspectors noted that the current Updated Safety Analysis Report (USAR),
Revision 18, Section 6.2.2, stated, These screens are conical in shape, manufactured
of Johnson Screen material and sized to prevent any particles with a mean diameter
greater than 1/8 inch from entering the sump. The inspectors determined that the
change from the original FSAR occurred with USAR Change Request R16-029, in
September 2000, which was processed without a 10CFR50.59 evaluation based on
condition report evaluation KAP 97-0885. Condition Report KAP 97-0885 was written in
May 1997 when the licensee discovered that the actual conical sump screen size was
1/8 inch by 15/32 inch which conflicted with the USAR Section 6.2, which stated that the
screens were sized to prevent particles larger than 1/8 inch from entering the sump.
The inspectors determined the evaluation for Condition Report KAP 97-0885
erroneously concluded that the current screen design met the intent of the USAR
statement and therefore a change to the USAR was warranted for clarification. The
conclusion was based, in part, on internal correspondence from November 1973 from a
licensee contractor to WPS Corporation which stated the response to AEC
Question 6.19 was, The screens installed over the containment sumps, which provide a
source of suction for the residual heat removal pumps, are of a conical shape,
manufactured of Johnson Screen material, which will admit particles having a mean
diameter of 1/8 inch or smaller. The 1997 condition report evaluation failed to
recognize that the AEC, based on WPS Corporations December 1971 response,
reviewed and approved a sump screen which was sized to prevent any particles larger
than 1/8 inch from entering the sump.
The inspectors identified the sump screen discrepancies to the licensee. The licensee
initiated a condition report to address the issue and performed an operability evaluation,
based on current ECCS recirculation performance characteristics (including flow
restrictions) which concluded the sump screens were operable but nonconforming, in
accordance with Generic Letter 91-18.
Enclosure
62
Analysis:
The inspectors determined that the failure to promptly correct this condition adverse to
quality was a licensee performance deficiency warranting a significance evaluation.
This issue was more than minor because the issue affected the Mitigating System
cornerstone attributes of design control for initial design and equipment performance
reliability and affected the associated cornerstone objective to ensure the reliability and
capability of systems that responded to initiating events to prevent undesirable
consequences. The inspectors evaluated the finding using IMC 0609, Appendix A,
Phase 1 screening and determined that the finding was of very low safety significance
because it was not a design or qualification deficiency that had been confirmed to result
in a loss of function per Generic Letter 91-18. The inspectors confirmed this through
review and verification of the licensees operability determination which concluded the
containment sump screens were nonconforming per Generic Letter 91-18.
The inspectors also concluded that the primary cause of this finding was related to the
cross-cutting area of problem identification and resolution, specifically the performance
characteristic of corrective actions.
Enforcement:
10 CFR 50, Appendix B, Criterion XVI, Corrective Action, required, in part, that
measures be established to assure that conditions adverse to quality, such as
deficiencies, deviations, and nonconformances were promptly corrected. Contrary to
this, the inspectors identified that conditions adverse to quality related to the sump
screen openings were not promptly corrected. Therefore, the inspectors determined
that this finding was a violation of 10 CFR 50, Appendix B, Criterion XVI. Because this
violation was of very low safety significance (Green) and documented in the licensees
corrective action program as CAP 023621 and CAP 023771, this finding was being
treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy.
The licensee took immediate corrective actions which included performing an operability
determination to determine if there were any immediate operability issues associated
with the larger screen size. In addition, the licensee was taking long term corrective
actions which would evaluate this issue in conjunction with the resolution of Generic
Safety Issue 191 and NRC Generic Letter 2004-02.
b.2
Inadequate Instructions and Procedures for Inspections and Cleaning of the Safety-
Related Containment Sump
Introduction:
A finding of very low safety significance (Green) was identified by the inspectors for a
violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, And
Drawings, regarding licensee instructions and procedures for containment sump
inspections. Specifically, the inspectors identified that current licensee procedures did
not require inspection or cleaning when boric acid or small debris might be present in
Enclosure
63
the containment sump; the licensees procedures for containment coatings did not
require inspection of the coating located inside the containment sump and had not been
inspected since initial application; and the licensees procedure for containment sump
gap inspections did not specify acceptance criteria to ensure this activity was
satisfactorily accomplished.
Description:
While performing an inspection of the containment sump, the inspectors noted that
there appeared to be standing water with very small debris and residual boric acid
residue in the safety-related containment sump directly below the sump screens. The
inspectors noted that the licensees outage schedule did not include an activity for
routine cleaning of the safety-related containment sump.
The inspectors determined that during refueling outages prior to 2001, the containment
sump was inspected and cleaned; however, a revision was made to the preventive
maintenance activity instruction PM34-037 in 2001, to only clean the sump if external
screen damage was verified. The inspectors questioned the licensee on the adequacy
of this condition, in light of industry operating experience regarding boric acid
accumulations in containment sumps and the residual boric acid currently located in the
sump. The licensee initiated CAP 023679 and concluded that the safety-related sump
required cleaning during the current refueling outage.
Following the cleaning of the containment sump the inspectors entered the containment
sump as part of the inspection. The inspectors noted that the containment sump was
concrete and had a thin clear coating (approximately 1-2 mils thick) which was later
determined to be Carboline 1340. The inspectors identified that residual boric acid
remained in certain sections of the sump which prohibited inspection of the containment
sump coating in those areas. The inspectors questioned the licensee regarding the
types of coating inspections performed in the containment sump and noted that General
Nuclear Procedure (GNP), GNP-08.22.03, Containment Walkdown to Monitor the
Performance of Service Level I Coatings, listed all the safety-related areas with
coatings in containment, except the containment sump. The licensee subsequently
determined that the coating was applied approximately 10 years prior and that a coating
inspection had never been performed since the original application of the coating.
Based on the inspectors questions, CAP 023840 was initiated and subsequent cleaning
of the remaining boric acid was performed. The licensee then performed a coating
inspection and identified some missing coating under the two containment sump suction
intakes; however, the remaining coating was intact.
The inspectors then verified the licensees procedure for inspection of the containment
sump screens, performed under GNP-12.17.01, Step 6.1.4 which required, an operator
to verify that there were no breaches of integrity in the Containment Sump B conical
screens and base plate attachments. The inspectors questioned the licensee whether
the acceptance criteria would ensure that the containment sump recirculation function
was maintained. The licensee initiated CAP 023816 and determined that the
acceptance criteria was not explicit enough to ensure satisfactory completion of the
activity, and additional clarifications were added to procedure GNP-12.17.01.
Enclosure
64
Analysis:
The inspectors determined that the failure to assure that inspections of the containment
sump and screens were prescribed by instructions or procedures appropriate to the
circumstances and containing appropriate acceptance criteria was a performance
deficiency warranting a significance evaluation. This finding was more than minor
because if left uncorrected the finding would become a more significant safety concern
and the issue affected the Mitigating System cornerstone attributes of equipment
performance reliability and procedure quality and affected the associated cornerstone
objective to ensure the reliability and capability of systems that responded to initiating
events to prevent undesirable consequences. The inspectors evaluated the finding
using IMC 0609, Appendix A, Phase 1 screening and determined that the finding was of
very low safety significance because it was not a design or qualification deficiency that
had been confirmed to result in a loss of function per Generic Letter 91-18.
Enforcement:
10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, And Drawings, required,
in part, that activities affecting quality be prescribed by documented instructions, or
procedures, of a type appropriate to the circumstances and shall include appropriate
quantitative or qualitative acceptance criteria. Contrary to this, inspections of the
containment sump and sump screens, activities affecting quality, were not prescribed by
documented instructions, procedures or drawings of a type appropriate to the
circumstances with appropriate acceptance criteria. Specifically, GNP-08.22.03,
Containment Walkdown to Monitor the Performance of Service Level I Coatings, was
not appropriate to the circumstances, in that, the procedure did not require routine
inspections of the coatings used on the internal portion of the safety-related containment
sump. Preventive maintenance activity PM34-037, was not appropriate to the
circumstances, in that, containment sump cleaning was not required if boric acid or
debris was located in the containment sump. General Nuclear Procedure GNP-12.17.01
did not contain appropriate acceptance criteria for determining that important activities
had been satisfactorily accomplished. The inspectors determined that this finding was a
violation of 10 CFR 50 Appendix B, Criterion V. Because this violation was of very low
safety significance (Green) and documented in the licensees corrective action program
as CAP 023679, CAP 023840 and CAP 023816, this finding was being treated as an
NCV, consistent with Section VI of the NRC Enforcement Policy.
The licensee subsequently initiated several corrective actions to address these issues
which included, but were not limited to:
inspection and cleaning of the safety-related containment sump;
inspection and assessment of the safety-related sump concrete coating;
revision of preventive maintenance activity PM34-037 to require inspection and
cleaning of the safety-related containment sump every refueling outage;
revision of GNP-08.22.03 to include inspection of the safety-related containment
sump concrete coating every refueling outage; and
revision of GNP-12.17.01 to include appropriate acceptance criteria for
determining that important activities were satisfactorily accomplished.
Enclosure
65
.3
Replacement Reactor Vessel Closure Head (RVCH) Fabrication (IP 71007)
a.
Inspection Scope
The original RVCH penetrations nozzles were fabricated from Inconel Alloy 600
material. These nozzles were welded to the RVCH with a partial penetration weld
fabricated from Inconel Alloy 182 weld filler metal. In recent years, several pressurized
water reactors have experienced pressure boundary leakage caused by primary water
stress corrosion cracking (PWSCC) of these materials.
During the 2004 refueling outage, the licensee elected to replace the RVCH and CRDM
housings. The design of the replacement RVCH is similar to the original RVCH, with
some notable exceptions as follows:
the new RVCH is constructed from a single piece forging which eliminates the
dome-to-flange weld;
the new CRDM housing design eliminates vents and seal welds;
the new RVCH design eliminates the spare and part length control rod
penetrations; and
the use of Inconel Alloy 600 was prohibited in fabrication of the new RVCH; for
example, the RVCH penetration tube material was changed from Inconel Alloy
600 to Inconel Alloy 690 which is more resistant to PWSCC.
From August 9, 2004, through August 13, 2004, and from October 18, 2004, through
October 28, 2004, the inspectors performed an on-site review of fabrication and
preservice nondestructive examination (NDE) records related to fabrication of the
replacement RVCH in accordance with Section 02.03 and Step 02.05.e of IP 71007,
"Reactor Vessel Head Replacement Inspection. This review was performed to confirm
that the manufacture and fabrication of the vessel head was completed in accordance
with Section III of the ASME Code, 1998 Edition through 2000 Addenda. Specifically,
the inspectors reviewed:
contract and Code specifications for materials used in the head forging, and
vessel head penetration nozzles and copies of heat treatment records including
plots of furnace temperature verses time and related documentation that
demonstrated the required temperatures and times were achieved to meet the
material specifications;
fabrication process sheets, fabrication drawings, and NDE records to verify that
this manufacturing process control plan included provisions for NDE in
accordance with applicable Code requirements;
fabrication process sheets, fabrication drawings and welding procedures to
ensure an appropriate sequence of welding operations and procedures existed
to support cladding the inside of the reactor vessel head with stainless steel to
meet Code requirements, design specifications and drawings;
Enclosure
66
certified material test reports for materials used in fabrication of the reactor
vessel head including weld materials to ensure Code material specifications were
met;
Nuclear Management Company surveillance audit records of the head fabricator
and subcontractors associated with welding activities (welding of J-groove welds,
head adaptor welds and head cladding), NDE activities, part identification/
traceability and drawing controls to confirm that these activities had been
properly controlled in accordance with the contract specifications or Code
requirements; and
deviation notices, subcontractor corrective action notices and Nuclear
Management Company communication issue resolution sheets to ensure that
fabrication related deviations were appropriately tracked, evaluated and
resolved.
b.
Findings
No findings of significance were identified.
.4
RVCH and CRDM Housing Replacement (71007)
a.
Inspection Scope
From October 18, 2004, through October 22, 2004, and November 30, 2004, through
December 3, 2004, the inspectors reviewed the licensees design changes associated
with the replacement of the RVCH and CRDM housings.
The inspectors reviewed replacement RVCH and CRDM housing certified design
specifications, certified design reports, American Society of Mechanical Engineers
(ASME) Code reconciliation reports, fabrication deviation notices, non-conformance
reports, and design calculations to confirm that the replacement RVCH and CRDM
housings were in compliance with the requirements of ASME Boiler and Pressure
Vessel Code,Section III, Subsection NB (1998 Edition including addenda through
2000 Addendum). Specifically, the inspectors confirmed that the design specifications
and design reports for the replacement RVCH and CRDM housings were certified by
registered professional engineers competent in ASME Code requirements. The
inspectors confirmed that adequate documentation existed to demonstrate the certifying
registered professional engineers were qualified in accordance with the requirements of
the ASME Code Section III (Appendix XXIII of Section III Appendices). The inspectors
also confirmed that the replacement RVCH and CRDM housings were provided as
Code NPT stamped components.
Enclosure
67
b.
Findings
Introduction:
The inspectors identified an unresolved item (URI) for potential non-compliance with the
ASME Code design requirements governing the attachment of RVCH nozzles with
partial penetration welds.
Description:
Partial penetration welds may be used to attach nozzles to the RVCH as permitted by
the ASME Code Section III, Paragraph NB-3337.3. For this joint design, Paragraph
NB-3337.3(b) allows the stress intensities resulting from pressure induced strains
(dilation of hole) to be treated as secondary provided that the requirements of
NB-3352.4(d), Attachment of Nozzles Using Partial Penetration Welds, and figure
NB-4244(d)-1, Partial Penetration Nozzle, Branch, and Piping Connections, are
fulfilled. In Design Calculation CN-RCDA-03-120, CRDM Head Adapter - ASME Code
Evaluation, Section 6.3.4, the licensee evaluated stresses in the J-groove weld region
resulting from pressure induced strains as secondary. However, the inspectors
identified that the licensees RVCH design may have deviated from the requirements of
NB 3352.4(d) and Figure NB-4244(d)-1.
For the attachment of nozzles using partial penetration welds,Section III
Paragraph NB-3352.4(d)(2) specifies that the minimum dimensions of Figure
NB-4244(d)-1 shall be met. In part, the corners of the end of each nozzle shall be
rounded to a minimum radius of one-fourth of the nominal thickness of the penetrating
part, or 3/4 inch, whichever is less. In addition, NB-3352.4(d)(3) specifies that the
corners of the end of each nozzle, extending less than (dtn)0.5 (where d is the outside
diameter and tn is the nominal thickness of the penetrating part) beyond the inner
surface of the part penetrated, shall be rounded to a minimum radius of one-half of the
nominal thickness of the penetrating part, or 3/4 inch, whichever is less.
The inspectors identified the following discrepancies with respect to these requirements:
The vent nozzles were ground flush with the inner surface of the RVCH. As
such, the inside corner should have been rounded using a minimum 1/2 tn
(0.126 inch) radius in accordance with NB-3352.4(d)(3). However, as indicated
on drawing L5-01DE109, the actual installed minimum radius was only
0.062 inch or approximately 1/4 tn.
The head adapter nozzles have a 4 inch outside diameter and 0.625 inch
nominal wall thickness. All corners were rounded with a minimum 0.177 inch
radius which is greater than 1/4 tn but less than 1/2 tn. Therefore, in accordance
with NB-3352.4(d)(3), these nozzles should extend not less than (dtn)0.5
(1.5811 inch) beyond the inner surface of the part penetrated. The inspectors
defined the inner surface of the part penetrated to be the J-groove weld toe. As
indicated on drawing L5-01DE173, the actual extension dimensions (column L6)
Enclosure
68
measured at nozzle location Nos. 28, 31, and 33 were less than the 1.5811 inch
requirement. Therefore, the minimum corner radius should have been 1/2 tn
(0.3125 inch) at these locations in accordance with NB-3352.4(d)(3).
The threads of the bottom of the instrumentation port head adapter tubes
were removed by machining which resulted in an outside diameter step
change. The measured distance from the J-groove weld toe to the diameter
step change at these locations was less than the 1.5811 inch cutoff specified by
NB-3352.4(d)(3). As such, the diameter step change corners should have been
rounded using 1/2 tn minimum radii. In addition, the corners at the bottom of the
instrumentation port head adapter tubes should have been rounded using a
minimum 1/4 tn radius in accordance with NB-3352.4(d)(2). Instead, as shown
on drawing L5-01DE111, two nozzle corner edges were chamfered between
0.005 inch and 0.03 inch, and the inside bottom corner edge was beveled at
30 degrees.
The inspectors judged that these potentially non-conforming conditions did not represent
a degraded condition which would affect operability of the new RVCH. However, the
inspectors considered these potential deviations from the design Code to be an
unresolved item (URI 05000305/2004009-04) pending further review by the licensee to
determine their position on application of these Code requirements. The licensee has
entered this issue into their corrective action system (CAP 024611).
.5
Activities Associated With Reactor Vessel Head Replacement (IP71007)
a.
Inspection Scope
The inspectors reviewed design and construction of Reactor Vessel Head (RV Head)
lifting and rigging equipment used to transport the new RV head along the ground,
through the containment equipment hatch, and into position in containment. In addition,
the inspectors directly observed rigging activities associated with all phases of the new
RV head being placed in containment. Crane and rigging equipment testing documents
and procedures for rigging the new RV head into position in the containment were
reviewed for adequacy. The inspectors directly observed the new RV head being
placed into position on the reactor vessel.
The inspectors observed preparations for setting the new RV Head onto the reactor
vessel. These preparations included:
RCS draindown to 6" below the Reactor Vessel flange;
Decontamination of the refueling cavity;
Foreign material exclusion controls utilized for the reactor cavity work;
Preparation of the New RV head, including installation of CRDM Coils and ARPI
coil stacks; and
Attachment and testing of rigging used to lift the New RV Head into position on
the vessel;
Enclosure
69
The inspectors also observed post-installation testing of the new RV Head including:
The licensees testing program and results;
Inspection of test records from CRDM and ARPI coil installation; and
Inspection for RV Head leakage at plant normal operating temperature and
pressure.
b.
Findings
No findings of significance were identified.
.6
Review of Institute of Nuclear Power Operations Report
The inspectors completed a review of the Institute of Nuclear Power Operations,
April 2004 Evaluation and Assistance Report for the Kewaunee Nuclear Power Plant,
received by the licensee in October 2004.
4OA6 Meetings
.1
Exit Meeting
On December 17, 2004, the resident inspectors presented the inspection results to
Mr. T. Coutu and other members of licensee management, who acknowledged the
findings presented. The inspectors asked the licensee whether any materials examined
during the inspection should be considered proprietary. No proprietary information was
identified.
.2
Interim Exit Meeting
Interim exit meetings were conducted for:
TI 2515/152, and the ISI procedure (IP 71111.08) inspections with Mr. T. Coutu
on October 22, 2004.
The reactor vessel head replacement fabrication review (IP 71007) with Mr. T.
Coutu and other Members of your staff on October 28, 2004, and the reactor
vessel head replacement safety evaluation and design reviews (IP 71007) on
December 3, 2004, and December 17, 2004.
Occupational Radiation Safety Access Control, ALARA and limited portions of
the transportation and radioactive material control programs during and
immediately following the licensees extended refueling and reactor head
replacement outage with Mr. T. Coutu on October 15, 22 and
December 17, 2004.
4OA7 Licensee-Identified Violations
The following violations of very low significance were identified by the licensee and are
violations of NRC requirements which met the criteria of Section VI of the NRC
Enforcement Manual, NUREG-1600, for being dispositioned as Non-Cited Violations.
Enclosure
70
Technical Specifications 3.3.a.1.B required that prior to exceeding 1000 psig
RCS Pressure that the SI System Accumulator Isolation Motor Operated Valves
(MOVs) be opened with power to the MOVs locked out. Contrary to this
requirement, the licensee exceeded 1000 psig RCS Pressure with the SI System
Accumulator Isolation Valves still closed. This violation of Plant TSs was of low
safety significance since no actual condition existed that required the
Accumulators to be functional to mitigate an event or accident condition. This
was documented in licensees CAP as CAP 024241.
10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
required, in part, that activities affecting quality be prescribed by document
instructions or procedures, of the type appropriate to the circumstances and shall
include appropriate acceptance criteria for determining that important activities
have been satisfactorily accomplished. Contrary to this requirement, the
licensee failed to ensure that Procedure FPP-08-09, associated with the plants
control room emergency zone envelope barrier control program was appropriate
to the circumstances and included sufficiently detailed guidance to ensure all
control room barriers were in their required positions. This violation was of low
safety significance due to the very short duration in which the situation
associated with this finding existed. This was documented in licensees CA
program as CAP 022205, ACE 002735, Maintenance Rule Evaluation 002409,
and RCE 000658.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Attachment
1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Nuclear Management Company, LLC
T. Coutu, Site Vice President
K. Hoops, Site Director
K. Davison, Plant Manager
R. Adams, ALARA Supervisor
L. Armstrong, Engineering Director
S. Baker, Radiation Protection Manager
J. Bennett, EP Instructor
A. Bolyen, QA Supervisor
J. Coleman, EP Manager
J. Egdorf, EP Supervisor
D. Fitzwater, Operations Training Supervisor
W. Flint, Chemistry Manager
D. Franson, Service Water System Engineer
S. Forsha, Quality Assurance Oversight Lead NMC Head Replacement
L. Gerner, Licensing Supervisor
E. Gilson, Security Manager
W. Goder, Operations Training General Supervisor
G. Harrington, Licensing
W. Hunt, Training Manager
D. Lohman, Operations Manager
K. Peveler, Manager, Engineering Programs
J. Pollock, Design Engineering Manager
B. Presl, NMC Security Consultant
S. Putman, Maintenance Manager
A. Rahn, SW and FAC Inspection Program Engineer
R. Repshas, Site Services Manager
J. Riste, Licensing Supervisor
J. Rozell, Simulator Support Team
D. Scherwinski, Training Instructor
T. Schmidli, Radiation Protection General Supervisor, Field Operations
J. Stafford, Assistant Operations Manager
J. Rozell, Simulator Support Team
J. Stoeger, Operations Training Supervisor
D. Scherwinski, Training Instructor
P. Sunderland, EP Coordinator
C. Tomes, Fleet Lead NMC Engineer Head Replacement
S. Zepplin, Simulator Support Team
Attachment
2
NRC Personnel
T. Kozak, Team Leader, Technical Support Section
J. Cameron, Project Engineer
J. Lamb, Project Manager
S. Reynolds, Acting Director, Division of Reactor Projects
Attachment
3
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Inadequate Control of Combustible Materials
(Section 1R05.1.b.1)05000305/2004009-02
Inadequate Corrective Action to Preclude Storage of
Oxygen Cylinders Next to Flammable Gas Cylinders
(Section 1R05.1.b.2)05000305/2004009-03
Potential Flooding in the Turbine Building Basement
(Section 1R06.2.b)05000305/2004009-04
Potential Non-compliance with ASME Code Governing
the Attachment of RVCH Nozzles with Partial
Penetration Welds (Section 1R17.2.b)05000305/2004009-05
Scaffolding Erected Too Close to Safety-Related
Equipment Required To be Operable
(Section 1R20.1.b.1)05000305/2004009-06
Inability to Close Containment Equipment Hatch
(Section 1R20.1.b.2)05000305/2004009-07
Reactor Building Ventilation Isolation Function Not
Available When Required (Section 1R20.1.b.3)05000305/2004009-08
Failure to Identify Inadequate Pre-Fire Strategies
(Section (4OA2.3.b)05000305/2004009-09
Non-conforming Condition on the Safety-Related
Containment Sump (Section 4OA5.2.c.1)05000305/2004009-10
Inadequate Instructions and Procedures for
Inspections and Cleaning of the Safety-related
Containment Sump (Section 4OA5.2.c.2)
Closed
Inadequate Control of Combustible Materials
(Section 1R05.1.b.1)05000305/2004009-02
Inadequate Corrective Action to Preclude Storage of
Oxygen Cylinders Next to Flammable Gas Cylinders
(Section 1R05.1.b.2)05000305/2004009-05
Scaffolding Erected Too Close to Safety-Related
Equipment Required To be Operable
(Section 1R20.1.b.1)
Attachment
4
Reactor Building Ventilation Isolation Function Not
Available When Required (Section 1R20.1.b.3)05000305/2004009-08
Failure to Identify Inadequate Pre-Fire Strategies
(Section (4OA2.3)05000305/2004009-09
Non-conforming Condition on the Safety-Related
Containment Sump (Section 4OA5.2.c.1)05000305/2004009-10
Inadequate Instructions and Procedures for
Inspections and Cleaning of the Safety-related
Containment Sump (Section 4OA5.2.c.2)
Discussed
Potential Flooding in the Turbine Building Basement
(Section 1R06.2.b)05000305/2004009-04
Potential Non-compliance with ASME Code Governing
the Attachment of RVCH Nozzles with Partial
Penetration Welds (Section 1R17.2.b)05000305/2004009-06
Inability to Close Containment Equipment Hatch
(Section 1R20.1.b.2)
Attachment
5
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection. Inclusion on this list does
not imply that the NRC inspectors reviewed the documents in their entirety but rather that
selected sections of portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
1R01
Adverse Weather Protection
Procedure GNP-12.06.01; Cold Weather Operations; Revision B
Procedure A-AAC-15; Abnormal Auxiliary Building Air Conditioning System Operation;
Revision E
Procedure A-TAV-16; Abnormal Turbine Building and Screenhouse Ventilation System
Operation; Revision P
Procedure PMP-08-07; FP - Hydrant Discharge House Test and House Station and
Floor Drain Inspection; Revision W
CAP 013674; PB Level A issue - PBNP Facility not prepared for Cold Weather on 1
November 2002; Sept. 26, 2003
CAP 018586; Adverse Weather Protection activities have not been timely; Oct. 23, 2003
1R02
Evaluation of Changes, Tests, or Experiments (71111.02)
DCR 3481; Reactor Vessel Head Replacement Project; Revision 0
50.59 Applicability Review; DCR 3481; dated August 16, 2004
50.59 Pre-Screening; DCR 3481; dated August 16, 2004
SCRN No.04-103; 10 CFR 50.59 Screening for DCR 3481; Revision 0
50.59 Applicability Review; DCR 3481 - Vendor (Westinghouse) Supporting
Calculations; dated November 3, 2004
50.59 Pre-Screening; DCR 3481 - Vendor (Westinghouse) Supporting Calculations;
dated November 10, 2004
Westinghouse Letter LTR-RCPL-04-145; Revision 1; Subject: Review of RRVCH and
CRDM Reference Documents for USAR-Related Methods of Evaluation; dated
November 15, 2004
50.59 Applicability Review; DCR 3481 - Vendor (Bigge Power Constructors) Supporting
Calculations; dated September 13, 2004
50.59 Pre-Screening; DCR 3481 - Vendor (Bigge Power Constructors) Supporting
Calculations; dated August 13, 2004
Procedure GNP-04.04.01; 50.59 Applicability Review and Pre-Screening; Revision C
Procedure GNP-04.04.02; 50.59 Screening and Evaluation; Revision C
1R04
Equipment Alignment
N-FW-05B-CL; Auxiliary Feedwater System Pre-startup Checklist; Revision AI
OPERM-205; Flow Diagram Feedwater System; Revision AX
N-SI-33-CL; SI System Prestartup Checklist, Revision AG
N-FW-05B-CL; Auxiliary Feedwater System Pre-startup Checklist; Revision AI
Attachment
6
OPERM-205; Flow Diagram Feedwater System; Revision AX
N-SI-33-CL; SI System Prestartup Checklist; Revision AG
OPERXK-100-2B; Flow Diagram SI System; Revision AM
OPERXK-100-29; Flow Diagram SI System; Revision AA
1R05
Fire Protection
Fire Protection Program Analysis; Revision 5
Fire Protection Program Plan; Revision 5
Operational Quality Assurance Program Description; Revision 22.a
FPP-08-08; FP - Control of Transient Combustible Materials; Revision D
1R06
Flood Protection Measures
USAR Section 2.6; Hydrology; Revision 18.
Letter from WPS to NRC; Letter No. NRC-98-102; Response to Supplemental Request
for Additional Information Regarding Individual Plant Examination for External Events
Submittal; September 28, 1998
Procedure E-0-5; Response to Natural Events; Revision K
CAP 003858; OEA 2001-082 - Temporary Flood Barriers Not Installed Following
Removal of; April 11, 2002
CAP 003187; Flooding Issue Screenhouse; February 20, 2002
CAP 002050; OEA 2001-082; May 31, 2001
CAP 008836; OEA 2001-061 - Flooding; May 10, 2001
CAP 013154; Potential Screenhouse Flooding Paths; Oct. 1, 2002
Letter from Pioneer Service & Engineering Co. to WPS.; Letter No. KP-S-2351; Check
List Item 9 Draft - Screenhouse High Water Protection; May 2, 1972
1R07
Heat Sink Performance
PMP-10-11; DGM - Diesel Generator Cooling Water Heat Exchanger Performance
Monitoring (QA-1); Revision C; November 20, 2003
GMP-137; Brush/Tube Scrubber Cleaning Heat Exchanger Tubes and Inspection;
Revision H; July 29, 2004
1R08
Inservice Inspection Activities
SP-06-258; Main Steam and Auxiliary Feedwater System Pressure Test; Revision G
SP-36-267; ASME Boiler and Pressure Vessel Code Class I System Pressure Test;
Revision 0
1R11
Licensed Operator Requalification
LRC-04-DY501; Cycle 04-05 Simulator Dynamic Scenario
Differences List Between Simulator and the Reference Plant
Attachment
7
1R12
Maintenance Effectiveness
GNP-08.20.04; Maintenance Rule MRFF and MPFF Evaluations; Rev. E
NAP-08.20; Maintenance Rule Implementation; Revision. D
Residual Heat Removal Unavailability Hours; April 2003 to September 2004
CAP 016291; RHR 11 Operability Following Actuator Replacement
CAP 021806; RHR 299A Failed to Open During SP-33-098A
MRE 1830; RHR 110 Bushing Fell off While Attempting to Open; 4/15/2003
MRE 1968; RHR System Leak Near RHR-500B; 4/5/2003
MRE 1597; RHR A Pressure Xmtr Out of Tolerance Low; 9/17/2002
OPERXK-100-18; Residual Heat Removal System; Revision AQ
OPERXK-100-29; SI System; Revision AA
WO 04-05792; RHR HX Outlet Loop Hdr Temp has failed low; 5/17/2004
WO 04-06887; TM-627A removed - Repair module; 6/1/2004
1R13
Maintenance Risk Assessment and Emergent Work Evaluation
GNP 08.04.01; Shutdown Safety Assessment, Revision L
Shutdown Safety Assessment Checklists, Control Room Logs, and Integrated Work
Schedule For The Week Of October 11, 2004
Shutdown Safety Assessment Checklists, Control Room Logs, and Integrated Work
Schedule For The Week Of October 18, 2004
Shutdown Safety Assessment Checklists, Control Room Logs, and Integrated Work
Schedule For The Week Of October 25, 2004
Shutdown Safety Assessment Checklists, Control Room Logs, and Integrated Work
Schedule For The Week Of November 1, 2004
1R14
Personnel Performance During Non-Routine Plant Evolutions
CAP 022946; Containment Sump A High Level Received; September 30, 2004
CAP 022983; Shroud Cooling Coil(s) Suspected Source of Leakage to Containment
Sump A; October 3, 2004
CAP 022984; Increased Indication on Containment Particular Monitor R-11; October 3,
2004
GNP 12.17.02; Containment Inspection During Operations; Revision C; August 26, 2004
Operational Decision-Making Exercise; Increased in-leakage into Containment Sump A
1R15
Operability Evaluations
CAP 023009; Turbine Driven AFW Pump OB Bearing Oil Level Above Normal Level
NMAC TR-1007461; Terry Turbine Maintenance Guide
GNP-11.08.03; Operability Determinations
CAP 023009; Turbine Driven AFW Pump OB Bearing Oil Level Above Normal Level
NMAC TR-1007461; Terry Turbine Maintenance Guide
GNP-11.08.03; Operability Determinations
CAP 023695; Shroud Cooling Coil Damaged During Installation; October 30, 2004
CAP 023333; FHA Control Room Boundary Damper Analysis Assumptions; October 17,
2004
Attachment
8
CAP 023124; As Found ACC System Flows Not Per Design Values; October 9, 2004
OBD 000100; As Found ACC System Flows Not Per Design Values; October 12, 2004
OPR 000076; As Found ACC System Flows Not Per Design Values; October 10, 2004
1R16
Operator Work-Arounds
Operator Workaround Status Sheet Dated October 25, 2004
Operator Workaround 04-08
Operator Workaround 04-07
Operator Workaround 04-06
Operator Workaround 04-04
Operator Workaround 04-03
Operator Workaround 04-02
NAD-12.07; Operator Workaround Rev B
1R17
Permanent Plant Modifications
LTR-RCUMP-04-61; Kewaunee Support Pin Design Equivalency Report; 11/10/04
Design Change Request 3494; Revision 1; 50.50 Applicability Review; 9/13/04
QF-0525 (FP-E-MOD-06); Revision 0
Final Guide Tube Replacement Support Pin Design Specifications and Supporting
Documents; 4/30/04
DCR-3481; Reactor Vessel Head Replacement Project; Revision 0
Design Specification No. 414A85; Control Rod Drive Mechanism (CRDM) Model L106A;
Revision 2
Document No. KW-KCS-04-0006; Design Report KW-KCS-04-0002; Revision 0
Addendum; Revision 3
Document No. KW-KCS-04-0002; Control Rod Drive Mechanism Design Report;
Revision 0
WCAP-16238-P; Kewaunee Nuclear Power Plant Replacement Control Rod Drive
Mechanism - Design Report; Revision 1
Addendum 1 to WCAP-16238-P; Revision 1; Kewaunee Nuclear Power Plant
Replacement Control Rod Drive Mechanism - Design Report; dated June 2004
Calculation Note No. WB-CN-ENG-04-4; Kewaunee CRDM ASME Code Section XI
Reconciliation; Revision 1
Calculation Note No. WB-CN-ENG-03-79; Kewaunee CRDM - Upper Latch Housing and
Lower Latch Housing (LLH) - ASME Qualification; Revision 1
Calculation Note No. WB-CN-ENG-04-19; Kewaunee CRDM - Rod Travel Housing
(RTH) ASME Qualification; Revision 0
Document No. KW-KCS-04-0004; Justification for Nonconformance Reports of
Replacement Control Rod Drive Mechanism; Revision 2
Document No. KW-KCS-04-0008; Additional Reconciliation of Design Report with Latest
Drawing Revision; Revision 0
Surveillance SP-49-074A; Control Rod Drop Time Test - Startup Measurements; dated
November 23, 2004
MHI-NMC-1630K; L5-03BJ040, Revision 2 - CRDM As-built Dimension Drawing; dated
June 14, 2004
NMC Letter KE-RRVCH-04-0290; Subject: CRDM As-built Dimensional Drawing,
L5-03BJ040, Revision 2, MHI-NMC-1630; dated June 22, 2004
Attachment
9
WEC Letter LTR-RCDA-04-596; Subject: Document Submittals MHI-NMC-1456K,
MHI-NMC-1457K, MHI-NMC-1458K, MHI-NMC-1593K, and MHI-NMC-1630K; dated
June 17, 2004
MHI Drawing L5-03BJ040; Control Rod Drive Mechanism, As-built Dimensional
Drawing; Revision 2
Reactor Vessel Closure Head and Control Rod Drive Mechanisms; ASME NPT
Component Certification; Mitsubishi Heavy Industries, Ltd.; dated June 14, 2004
DCR-3481; Reactor Vessel Head Replacement Project; Revision 0
Design Specification No. 414A84; Replacement Reactor Vessel Closure Head
(RRVCH), (ASME B&PV Code,Section III, Class 1, Subsection NB); Revision 3
Design Specification No. 418A75; Addendum to Design Specification 414A84;
Revision 3,
Replacement Reactor Vessel Closure Head (RRVCH), (ASME B&PV Code,Section III,
Class 1, Subsection NB); Revision 0
Document No. L5-01DE510; Kewaunee Nuclear Power Plant, Replacement Reactor
Vessel Closure Head Design Report; Revision 1
Document No. L5-01DE511; Kewaunee Nuclear Power Plant, Replacement Reactor
Vessel Closure Head, Design Report L5-01DE510 Revision 1 Addendum; Revision 1
WCAP-16237-P; Kewaunee Nuclear Power Plant Replacement Reactor Vessel Closure
Head - Design Report; Revision 1
Addendum 1 to WCAP-16237-P; Revision 1; Kewaunee Nuclear Power Plant
Replacement Reactor Vessel Closure Head - Design Report; dated June 2004
Calculation Note No. CN-RCDA-04-20; Kewaunee RRVCH, ASME Section XI Code
Reconciliation; Revision 0
Calculation Note No. CN-RCDA-03-106; Kewaunee Nuclear Power Plant RVCH
Analysis Procedure; Revision 3
Calculation Note No. CN-RCDA-03-120; NMC Kewaunee Replacement Reactor Vessel
Closure Head, CRDM Head Adapter ASME Code Evaluation; Revision 0
Calculation Note No. CN-RCUWF-04-1; Kewaunee Replacement Head Project - Closure
Head Flange ASME Code and Leakage Evaluation; Revision 1
Document No. KBS-20040284; Justification for Nonconformance Reports of
Replacement Reactor Vessel Closure Head; Revision 2
Document No. KBS-20040336; Fracture Evaluation of Kewaunee RRVCH and Point
Beach Unit 2 RRVCH; Revision 1
Deviation Notice No. 60749; UT Requirement for Head Forging; Revision 1
Deviation Notice No. 62421; Number of Samples for Vent Pipe/Height of CRDM
Housing; Revision 1
NMC Letter KE-RRVCH-04-0372; Subject: NMC Review of WEC DN 62421 Revision 1,
WPS-04-130, Deviation Notice; July 2, 2004
NMC Letter KE-RRVCH-04-0425; Subject: NMC Review of WEC Letter
LTR-RCDA-04-803 Regarding DN 62421; Revision 1; August 16, 2004
WEC Letter LTR-RCDA-04-803; Subject: Response to NMC Letter KE-RRVCH-
04-0372 Regarding DN 62421; dated July 27, 2004
Nikko Inspection Report No. 2033-01-13; Closure Head Forging, Archive Sample,
Coupons C1 & C2; dated April 10, 2003
MHI-NMC-1456K, L5-01DE171; Revision 2 - As-built Drawing (1/3); dated June 11,
2004
MHI-NMC-1457K, L5-01DE172; Revision 3 - As-built Drawing (2/3); dated June 11,
2004
Attachment
10
MHI-NMC-1458K, L5-01DE173; Revision 4 - As-built Drawing (3/3); dated June 11,
2004
NMC Letter KE-RRVCH-04-0285; Subject: As-built Dimensional Drawing (1/3),
L5-01DE171, Revision 2, HI-NMC-1456; dated June 22, 2004
NMC Letter KE-RRVCH-04-0286; Subject: As-built Dimensional Drawing (2/3),
L5-01DE172; Revision 3, MHI-NMC-1457; dated June 22, 2004
NMC Letter KE-RRVCH-04-0287; Subject: As-built Dimensional Drawing (3/3),
L5-01DE173, Revision 4, MHI-NMC-1457; June 22, 2004
WEC Letter LTR-RCDA-04-596; Subject: Document Submittals MHI-NMC-1456K,
MHI-NMC-1457K, MHI-NMC-1458K, MHI-NMC-1593K, and MHI-NMC-1630K; June 17,
2004
MHI Drawing L5-01DE109; Replacement Reactor Vessel Closure Head, Closure Head
and Adapter Housing Assembly; Revision 4
MHI Drawing L5-01DE111; Replacement Reactor Vessel Closure Head, Instrumentation
Port Head Adapter 2/2; Revision 2
MHI Drawing L5-01DE115; Replacement Reactor Vessel Closure Head, Spare CRDM
Adapter; Revision 1
MHI Drawing L5-01DE171; Replacement Reactor Vessel Closure Head, As-built
Drawing (RV Closure Head) 1/3; Revision 2
MHI Drawing L5-01DE172; Replacement Reactor Vessel Closure Head, As-built
Drawing (RV Closure Head) 2/3; Revision 3
MHI Drawing L5-01DE173; Replacement Reactor Vessel Closure Head, As-built
Drawing (RV Closure Head) 3/3; Revision 4
Reactor Vessel Closure Head and Control Rod Drive Mechanisms, ASME NPT
Component Certification, Mitsubishi Heavy Industries, Ltd.; dated June 14, 2004
1R19
Post-Maintenance Testing
SP-10-211-1; Inspection of Diesel Generator B- Electrical
SP-10-211-2; Inspection of Diesel Generator B- Mechanical
SP-10-211-3; Inspection of Diesel Generator B- Component Retest
SP-42-047B; Diesel Generator B Operational Test
SP-34-339B; RHR Pump B Full Flow Test at Refueling Shutdown - IST
CMP-34-01; RHR - RHR Pump Overhaul
1R20
Refueling and Outage Activities
N-O-04; 35 percent To HSD Condition
N-O-05; Plant Cooldown From Hot Shutdown To Cold Shutdown Condition
N-RHR-34; Residual Heat Removal System Operation
N-TB-54; Turbine and Generator Operation
N-O-02; Plant Start Up From Hot Shutdown To 35 percent Power
MRS-SSP-1637; Replacement RV Head Field Installation
MRS- GEN-1148; CRDM and ARPI Coil Resistance and Insulation Resistance Testing
PMP-57-26; Reactor Building Polar Crane Mechanical Maintenance
Bigge Document No. 2100-P7; Procedure For Load Tests of Kewaunee and Ginna
Upending/Downending Frames and Spreader Bar SB-224 As Lift Rigging In Vertical
Position
Attachment
11
MRS-SSP-1690; Kewaunee RRVH Procedure To Haul New Head To Containment and
Upend
MRS-SSP-1678; Kewaunee RRVH Procedure for Off-load from Delivery Vehicle,
Transfer to Bigge Transporter, Transfer to Assembly Site, and Remove MHI Container
MRS-SSP-1687; Kewaunee RRVH Procedure to Install and Remove Containment
Building Runway
Bigge Mechanical Drawings Package For Job Number 2100 (Kewaunee Head
Replacement)
Carpenter Rigging and Supply Company Certificate of Test Serial Number 44840-01
Carpenter Rigging and Supply Company Certificate of Test Serial Number 44897-1
GNP-08.22.03; Containment alkdown to Monitor the Performance of Service Level I
Coatings; Revision A; May 4, 2004
GNP-08.04.01; Shutdown Safety Assessment; Revision K; March 9, 2004
Shutdown Safety Assessment Checklist; October 8, 2004
Tagout Tag List; Tagout Group: Refueling Outage 27; Tagout 50-11-CONT-00001-(001)
GNP 02.07.01; Refueling Operations - Logkeeping, Watchstanding, and Shift Turnover;
Revision A; May 25, 2004
E-FH-53A; Dropped or Damaged Fuel Assembly; Revision D; August 17, 2001
E-FH-53B; Loss of Reactor Cavity Inventory During Fuel Movement; Revision D;
February 19, 2004
FP-OP-COO-01; Conduct of Operations; Revision 1
Operations Department Instruction Book; Protected Equipment; Revision 6; October 11,
2004
RCE 000616; Damaged Rod Control Cluster Assembly (RCCA)
Shutdown Safety Assessment Checklist; October 12, 2004; Time 0600-1800
Shutdown Safety Assessment Checklist; October 10, 2004; Time 0600-1800
Shutdown Safety Assessment Checklist; October 10, 2004; Time 1800-0600
Shutdown Safety Assessment Checklist; October 11, 2004; Time 0600-1800
Shutdown Safety Assessment Checklist; October 11, 2004; Time 1800 -0600; Rev 1
N-0-01-CLE; Backseated Valves Checklist; Revision D; April 18, 2002
1R22
Surveillance Testing
SP-33-110; Diesel Generator Automatic Test
SP-56-078; Containment Isolation Trip Test
SP-33-191; SI Flow Test - IST; Revision V; August 26, 2004
SP-05B-283A; Motor Driven AFW Pump A Full Flow Test - IST; Revision H;
September 30, 2004
SP-05B-283B; Motor Driven AFW Pump B Full Flow Test - IST; Revision H;
September 30, 2004
CAP024309; Relay Chatter During SP-49-074A, Control Rod Drop Timing Test;
November 29, 2004
SP-49-074A; Control Rod Drop Time Test - Startup Measurements; Revision S;
November 29, 2004
SP-36-082; Reactor Coolant System Leak Rate Check; December 19 and
December 20,2004
Attachment
12
1R23
Temporary Plant Modifications
TCR 04-13; Raise the setpoint of SFP Temperature Switches 12007 and 12012
Engineering Change Notice (ECN)-04-13-01; Raise the setpoint of SFP Temperature
Switches 12007 and 12012
CAP 023890; 50.59 not updated on TCR 04-13 (Spent) Fuel High Temperature Alarm;
November 8, 2004
1EP6 Drill Evaluation
Emergency Preparedness Drill and Exercise Manual; 4th Quarter 2004 Drill
2OS1 Access Control to Radiologically Significant Areas
CAP 019414; Unqualified Individual Attempting to Fee Release Material from the
Radiologically Controlled Area; dated January 5, 2004
CAP 019896; Barriers for Locked High Radiation Areas; dated February 9, 2004
CAP 020143; Unnecessary Dose Received for Plant Inspection; dated February 25,
2004
CAP 020885; Posting Practices; dated April 20, 2004
CAP 021140; Exposure Received During Quarterly Plant Inspection in Locked High
Radiation Area; dated May 10, 2004
CAP 021464; Human Error Traps in Requirements for Issuance of Neutron Bubble
Dosimetry; dated June 7, 2004
CAP 022816; Radiation Protection Department Missed an Inventory of the Locked High
Radiation Keys; dated September 22, 2004
CAP 022966; Foreign Material in Spent Fuel Transfer Canal; dated October 1, 2004
CAP 023148; HP Technician Performed Initial Confined Space Survey Without Support
Person; dated October 10, 2004
CAP 023247; Electronic Dose Alarm Received; dated October 13, 2004
CAP 023254; Inadequate ALARA Brief; dated October 14, 2004
LER 050-305/2004-002-0; TS Sections 4.13 (b) and (e) Requirement for Leak Tests of
Sources Transferred from Storage for Use or to Another Licensee
KNPP HP-01.019; Radiological Postings, Boundaries and Barricades; Revision F
KNPP HP-01.021; Issuance and Control of Locked High Radiation Area Keys;
Revision C
RWP 7; General Decontamination and Support of Decontamination; Revision 0
RWP 11 RVCH Disassembly/Reassembly
RWP 15; NDE Testing; Revision 0
RWP 36; Transfer Canal Inspect and Decontamination; Revision 0
RWP 93; 626 Containment-Seal Table Area; Revision 0
RWP 98; Conoseal Work; Revision 0
RWP 115; 592 Containment Sump-C Sump Area; Revision 0
RWP 182; Reactor Coolant Pump Seal Work; Revision 0
RWP 200; General Clean-up and Decontamination of Containment; Revision 0
NAD-01.11; Dosimetry and Personnel Monitoring; Revision L
KNPP HP-01.016; Radiation Work Permit - Preparation, Issuance and Termination;
Revision H
Attachment
13
Personnel Contamination Outage Report for 2004 (undated draft)
KNPP HP-03.001; Shallow Dose Equivalent Calculation; Revision H
KNPP HP-03.008; Evaluation of Inhalations or Ingestions; Revision C
KNPP HP-03.009; Calculating Internal Dose from Whole Body Counter Results;
Revision D
Selected Whole Body Count Results and Intake Dose Assessment Records for
October 9, 2004 - December 12, 2004
CAP 023163; LHRA Entry Without Recorded Brief; dated October 11, 2004
CAP 024161; LHRA Key Issued in Violation of Procedure; dated November 22, 2004
2OS2 As Low As Is Reasonably Achievable Planning And Controls
ALARA Plan 04-005; Reactor Head Replacement Project ALARA Plan; dated
September 29, 2004
ALARA Plan 04-006; Reactor Coolant Pump Work and Support; dated September 29,
2004
CAP 019748; Tag-out for Work Not Identified; dated January 28, 2004
CAP 019820; Poor Timing of Work for ALARA Considerations; dated February 2, 2004
CAP 020642; New Procedure Issue With No Prior Briefing or Training; dated April 1,
2004
CAP020664; Possible Violation of Newly Issued Procedure; dated April 2, 2004
KNPP HP-01.017; Self-Assessment of Radiation Protection Program; Revision D
KNPP HP-03.011; Special Dosimetry Issuance; Revision F
KNPP HP-04.006; Control and Use of HEPA Vacuums and Portable Air Filtration Units
in Radiologically Controlled Areas; Revision B
KNPP HP-05.004; Radiation/Contamination Survey and Airborne Radioactivity Sampling
Schedules; Revision Q
NAD-01.23; ALARA Program; Revision F
Historical Outage Exposure Performance Data (undated)
Exposure Performance Summary for all Outage RWPs for Various Periods Between
October 9 and December 4, 2004
KNPP HP-02.003; Evaluation for Use and Issuance of Respiratory Protection
Equipment; Revision G
KNPP HP-04.007; ALARA Plan Writers Guide; Revision A
KNPP HP-04-001; ALARA Plan; Revision G
NAD-08.03; Radiation Work Permit; Revision I
ALARA Plan 04-011 (dated September 24, 2004), associated Pre-Job ALARA Planning
Checklist, ALARA Comment Sheet, and RWP 113 along with its Briefing Form; Bottom
Mount Insulation Inspection and Replacement Plan
Minutes of November 4, 2004 Radiological Performance Committee; Bottom Mount
Insulation Project Issues; dated November 15, 2004
Work In-Progress ALARA Reviews for ALARA Plan 04-011 and RWP 113; Bottom
Mount Insulation Inspection and Replacement; dated October 17, November 4, 22 and
25, 2004
Daily Cumulative and Individual Worker Exposures for RWP 113; Bottom Mount
Insulation Project
ALARA Plan 04-001 (dated September 29, 2004), associated Pre-Job ALARA Planning
Checklist, ALARA Comment Sheet, and RWP 92 along with its Briefing Form; Refueling
ALARA Plan
Attachment
14
Work In-Progress ALARA Reviews for ALARA Plan 04-001 and RWP 92; Reactor Head
Disassembly/Reassembly and Support; dated October 17 and November 25, 2004
ALARA Plan 04-014 (dated September 20, 2004), associated Pre-Job ALARA Planning
Checklist, ALARA Comment Sheet, and RWP 103 and 106 along with its Briefing
Forms; In-Service Inspection ALARA Plan
ALARA Plan 04-019 (dated September 20, 2004), associated Pre-Job ALARA Planning
Checklist, RWP 12 along with its Briefing Form; Motor Operated Valve Maintenance and
Testing Work Scope ALARA Plan
ALARA Plan 04-012 (dated September 29, 2004), Associated Pre-job ALARA Planning
Checklist, ALARA Comment Sheet, and RWP 199 along with its Briefing Form; Scaffold
and Support
CAP 023254; Inadequate ALARA Brief; dated October 14, 2004
CAP 023678; Inconsistent Expectations for Proper Attire in Containment; dated
October 29, 2004
KSA - KIPP-04-01; Source Term Reduction Program Self-Assessment; dated
February 24, 2004
KNPP HP-04.008; Hot Spot/Hot Line Tracking, Trending and Mitigation; Revision B
Steam Generator Loop Marker Survey Results for 1982 - 1993
2PS2 Radioactive Material Processing and Transportation
CAP 024203; Wrong Revision of Form Used for Radioactive Shipment; dated
November 24, 2004 [Self-Revealed Issue based on NRC Questions]
EC-0230; Envirocare of Utah, Inc. Radioactive Waste Profile Record; dated
September 1, 2004
EC-0230-SNM; Envirocare of Utah, Inc. Special Nuclear Material Exemption Certificate;
dated September 1, 2004
EC-1800; Envirocare of Utah, Inc. Notice to Transport; dated September 28, 2004
ER-03-010; Duratek Engineering Report - Characterization of Kewaunee Nuclear Power
Plant Reactor Pressure Vessel Head; dated March 5, 2004
E&L-037-04; Update of Characterization of Kewaunee RPVH; dated October 19, 2004
HP-09.031; Radioactive Material Shipping; Revisions A and B
Manifest 0845-08-0001; Uniform Low-Level Radioactive Waste Manifest, Shipping
Paper, and Vehicle/Package Surveys for the Old RVCH (LSA-II), Shipped to Envirocare
of Utah, Inc., Clive, UT; dated November 15, 2004
PL-DTK-04-002; Transportation and Emergency Response Plan - Kewaunee Reactor
Head Disposal Project; dated June 28, 2004
2PS3 Radioactive Material Control
RPJG-40; RP Job Guideline - Reactor Head Replacement Project; dated
September 2004
RWP 110; Remove Old RVCH from Containment to North Lot and Prepare for Off-Site
Shipment; Revision 0
Attachment
15
4OA1 PI Verification
NEI 99-02; Regulatory Assessment Performance Indicator Guideline; Revision 2;
LER 2003-002; Diesel Generator Failed Start Test Caused by Start Relay; Revision 0;
LER 2003-006; Component Cooling Water R-17 Radiation Detector Pipe Assembly
Leakage; Revision 0;
LER 2004-008; Control Room Boundary Door Found Ajar; Revision 0
Various Dosimetry Egress Transactions, Personal Contamination Outage (Draft) Report,
and Selected Intake Dose Assessments for the period mid-2003 through December 15,
2004
GNP-03.18.01; NRC Performance Indicators Reporting Instructions; Revision H
CAP Database Listing for Selected Keyword Searches for the period May 2003 -
December 12, 2004
4OA2 Identification and Resolution of Problems
CAP 021901; Lack of Warnings or Training for Actions Needed if a Loss of Fire Water
Occurs; dated July 20, 2004
CAP 021915; Hydrogen and Propane Gas Lines Are Not Identified in the Fire
Strategies; dated July 21, 2004
PFP-17; Charging Pump, Boric Acid Concentrate Pump & Residual Heat Removal
Pump Pit Areas; dated May 7, 2004
Fire Protection Program Analysis; Revision 5
Fire Protection Program Plan; Revision 5
4OA3 Event Followup
Licensee Event Report 2004-003; Control Room Boundary Door Found Ajar-Accident
Analysis Assumptions Impacted
Licensee Event Report 2004-003-01; Supplemental Report to Control Room Boundary
Door Found Ajar-Accident Analysis Assumptions Impacted
FPP-08-09; Fire Plan Procedure "Barrier Control"; Revision F
CAP 022205; Door 152 Control Room HVAC Elevator Door found open by NAO
ACE 002735; Door 152 Control Room HVAC Elevator Door found open by NAO
RCE 000658; Door 152 Control Room HVAC Elevator Door found open by NAO
CAP 021686; TS Surveillance Violation, T.S. 4.13. E or T.S. 4.13. F; June 25, 2004
4OA5 Other Activities
RFT012563; Sump DebrisBulletin 2003-01 - Option 2 Analysis
RFT013870; Develop and Implement Training on Sump Clogging by 12/19/03-NRC
Commitment
Attendance Report by LP ID for LRC-03-SE601; Monday, October 25, 2004
Simulator Exercise Guide; SEG LRC-03-SE601; LB LOCA, Containment Sump
Recirculation; October 8, 2003
Attachment
16
CAP 023615; Potential Gap Between Training Conducted and NRC Commitment
Correspondence from KNPP to NRC; NRC Bulletin 2003-01, Potential Impact of Debris
Blockage on Emergency Sump Recirculation at Pressurized-Water Reactors; 60-Day
Response; August 7, 2003
Correspondence from KNPP to NRC; Supplement to 60-Day Response to NRC
Bulletin 2003-01, Potential Impact of Debris Blockage on Emergency Sump
Recirculation at Pressurized-Water Reactors; May 17, 2004
Correspondence from NRC to KNPP; Request for Additional Information Regarding
Response to NRC Bulletin 2003-01 (TAC No. MB9584); September 7, 2004
KNPP Document Data Sheet; Containment Survey Screens; P.O. No. K-651;
September 26, 1973
Drawing XK-651-1; Conical Screen; August 1, 1973
Drawing 237127A-S-237; Reactor Building Concrete-Sections and Details
Correspondence from Pioneer Service and Engineering Company to Wisconsin Public
Service Corporation; KP-S-1966; Answers to AEC Questions #10
USAR Change Request B16-029; September 19, 2000
Correspondence from U.S. Atomic Energy Commission to Wisconsin Public Service
Corporation; September 23, 1971
Correspondence from Wisconsin Public Service Corporation to U.S. Atomic Energy
Commission; Amendment No. 13 to the Application for Construction Permit and
Operating License for the KNPP; December 15, 1971
CAP 023816; Containment Sump Screen Inspection Criteria Unclear
CAP 023840; Containment Sump B Epoxy Coating
CAP 023679; Containment Sump B Requires Cleaning
Action Request Form; November 16, 2004; Void in Concrete Under East Inlet to 1A
RHR Pump
KNPP Work Request Form; Sequence Number 209941; Apply Carboline 1340 to
Concrete Floor; Ref. HP 8.05; Contact Rich Bardon; November 11, 1996
KNPP Work Request Form; Sequence Number 206649; Remove Remaining Coatings
Found on Concrete and Steel Surfaces Inside Containment Sump B; May 12, 1995
DCR 2736; Removal of Containment Sump B Protective Coatings
Correspondence from Wisconsin Public Service Corporation to NRC; 120-Day
Response to NRC Generic Letter 98-04; November 12, 1998
Incident Report 87-29; Identified Damage to Containment Sump B Floor Coating
CAP 023771; Potential Nonconformance Containment Sump B
KAP 471; Unqualified Coatings in Containment
CAP 013455; OEA 2003-230 - Potential ECCS Sump Blockage Due to Born
Accumulation
CA 007256; Evaluate Need for Periodic Inspection of Containment Sump B and, if
Necessary, Generate Work Instructions
CAP 017108;Bulletin 2003-01 Response Quantities of Containment Debris
CA 012689; Volume of Debris in Containment
CAP 006773; Potential Discrepancy was Discovered Between the Containment Sump B
Design
CAP 023932; Missed Opportunity to Inspect Containment Sump B - Rework
RFT 012562; Sump DebrisBulletin 2003-01 - Option 2 Analysis
Attendance Report by LPID; BR03-109; Containment Sump Blockage (NRC Bulletin 2003-01); Monday, October 25, 2004
Attachment
17
CAP 018297; Response to NRC Bulletin 2003-001: Impact of Debris Blockage
Emergency Sump Recirculation
Reactor Vessel Head Replacement
Certified Material Test Reports:
Reactor Vessel Closure Head; dated April 11, 2003
Closure Cap; dated December 11, 2003
Instrument Port Head Adaptor; dated April 7, 2003
Vent Pipe; dated November 5, 2003
Latch Housings NKM806A,B,C,J; dated May 9, 2003
NX3167JK, WELTIG 52; dated November 18, 2003
NX2686JK, WELTIG S52; dated November 5, 2003
304372, WELAC 152; dated September 4, 2003
A3302N, LBL-96; dated May 30, 2003
A3301N, NC-38LK; dated May 30, 2003
A1071213N, NC-39LK; dated May 30, 2003
2L6712025, USB-308L; dated May 30, 2003
2L6612029, USB-309L; dated May 30, 2003
BF060331, ER308L; dated June 9, 2004
BHA0406, THS-316LK; dated November 5, 2003
BF36099, SATY-316LK; dated January 7, 2004
AH4218, DW-100; dated April 22, 2004
Communication Issues Resolution Sheets:
CIRS 03-088N; No Angle Beam Test for Latch Housing; dated September 11, 2003
CIRS 03-121N; 100 Percent DAC Exceeded on Latch Housing; dated October 24, 2003
CIRS 03-122N; Two 50 Percent DAC Indications on CRDM Head Adaptor; dated
October 24, 2003
CIRS-03-125N; Vent Pipe Drawing Error; dated October 30, 2003
CIRS-03-127N; Straight Beam UT for Bi-Metallic Weld; dated October 30, 2004
CIRS-04-027N; Strip Cladding Weld Metal Certification; dated February 4, 2004
CIRS-04-068N; Weld Data Sheets for J-Groove Welds; dated March 17, 2004
CIRS-04-097M; Kewaunee CMTR Issues; dated May 26, 2004
CIRS-04-109N; Weld Filler Metal CMTRs; dated April 16, 2004
Deviation Notices:
DN 60679, Unsat UT on Keyway and Mating Surface; dated September 22, 2003
DN 60681, Unclear PT Procedure; dated August 27, 2003
DN 60684, Use of Demineralized Water; dated October 20, 2003
DN 60741; Repair Vent Pipe; dated December 4, 2003
DN 60749; 20 percent DAC UT of Head; dated March 11, 2004
DN 60751; Inadequate UT Procedure; dated March 2, 2004
DN 60846; Uncontrolled Welding and PT; dated April 30, 2004
Attachment
18
Drawings:
JSW Drawing, N148737-1; Closure Head Forging Configuration at QT; Revision 2
JSW Drawing, N148737-M; Closure Head Forging Detail of Test Coupons; Revision 2
MHI Drawing, L5-01DE 201; 2-Loop Closure Head Forging; Revision 3
MHI Drawing, L5-01DE 202; Vent Pipe; Revision 1
MHI Drawing, L5-01DE 204; Instrument Port Head Adaptor Flange; Revision 1
MHI Drawing, L5-01DE 205; Spare CRDM Head Adaptor Flange; Revision 0
MHI Drawing, L5-01DE 206; Closure Cap; Revision 1
MHI Drawing, L5-01DE 001; Closure Head Outline Drawing; Revision 7
MHI Drawing, L5-01DE 002; Closure Head Outline Drawing; Revision 3
MHI Drawing, L5-01DE 101 &102; Closure Head General Assembly; Revision 5
MHI Drawing, L5-01DE 103; Closure Head Welding; Revision 1
MHI Drawing, L5-01DE 104, Closure Head Welding, Revision 1
MHI Drawing, L5-01DE 105 &106; Closure Head Machining; Revision 1
MHI Drawing, L5-01DE 107 & 108; Closure Head Penetration Position; Revision 1
MHI Drawing, L5-01DE 109 &110, Closure Head & Adaptor Housing Assembly,
Revision 4
MHI Drawing, L5-01DE 111; Instrument Port Adaptor; Revision 2
MHI Drawing, L5-01DE 112; Vent Pipe; Revision 2
MHI Drawing, L5-01DE 114 &115; Spare CRDM Head Adaptor; Revision 2
Nuclear Management Company Surveillance Reports:
2003-0124; Review of Qualified Welders and Weld Operators, Review of Calibration
Records for the Measuring Devices for Weld Overlay Cladding; dated June 6, 2003
2003-0132; Monitor Weld Overlay Cladding on Inner Surface of RVCH; dated June 20,
2003
2003-0163; Witness UT for Overlay Weld of Keyway; dated July 25, 2003
2003-0185; Witness Activities for the Kewaunee Nuclear Power Plant Head
Replacement Project; dated August 21, 2003
2003-0188; Fit-Up Inspection of Butt Joint Between Latch Housing and Head Adapter;
dated August 19, 2003
2003-0252; Remoter Visual Inspection for Inner Surface of Rod Travel Housings, UT for
Seamless Stainless Steel Pipe for Vent Line; dated October 3, 2003.
2004-0020; PT for J-weld at MHI, Review Final PWHT Chart for RVCH; dated
January 16, 2004
2004-0021; Witness PT for J-Groove Welds, Review of Welder Certification Records;
dated January 23, 2004
2004-0048; PT for J-Weld of Head Adapter and Vent Pipe to RVCH, Monitoring of
Welding for J-weld of Head Adaptor to RVCH; dated February 13, 2004
2004-0062; PT on Closure Cap after Machining, Monitoring of Welding of Butt Joint of
Latch Housing to Rod Travel Housing; dated March 12, 2004
2004-0087; Monitored Welding Between Latch Housing and Rod Travel Housing; dated
March 19, 2004
2004-0089; Manufacturing Process for CETNA Parts; dated February 4, 2004
2004-0093; Monitoring of Welding Operations for Closure Cap, UT of Butt Weld of Rod
Travel Housing to Latch Housing, UT and ECT for Vent Pipe Penetration at MHI; dated
April 9, 2004
Attachment
19
2004-0102; UT for Butt Weld of Rod Travel Housing to Latch Housing; dated April 24,
2004
2004-0115; PT for Upper Surfaces of Flange and Stud Holes of RVCH, PT for J-welds
and Alloy 690 Tubes, RT Films for Butt Welds of CRDM Housings, UT for Closure Cap,
Hydro Pressure Test for RVCH; dated May 8, 2004
Nondestructive Examination Records:
Pressure Test Record- Reactor Vessel Closure Head; dated May 6, 2004
Magnetic Particle Examination Record, Exterior Surface of RVCH; dated May 25, 2004
Magnetic Particle Examination Record, Lift Lug Welds; dated May 24, 2004
Liquid Penetrant Examination Record, Vent Pipe Welds; dated May 24, 2004
Liquid Penetrant Examination Record, RVCH Cladding; dated May 25, 2004
Liquid Penetrant Examination Record, Indication J-Groove Weld 4 Inch Tube; dated
May 25, 2004
Liquid Penetrant Examination Record, Indication J-Groove Weld 4 Inch Tube; dated
May 24, 2004
Liquid Penetrant Examination Record, Indication J-Groove Weld 4 Inch Tube; dated
May 24, 2004
Liquid Penetrant Examination Record, Indication J-Groove Weld 4 Inch Tube; dated
May 24, 2004
Liquid Penetrant Examination Record, Indication J-Groove Weld 4 Inch Tube; dated
May 24, 2004
Liquid Penetrant Examination Record, Indication J-Groove Weld 4 Inch Tube; dated
May 24, 2004
Liquid Penetrant Examination Record, Indication J-Groove Weld 4 Inch Tube; dated
May 24, 2004
Liquid Penetrant Examination Record, Indication J-Groove Weld 4 Inch Tube; dated
May 24, 2004
Liquid Penetrant Examination Record, Indication J-Groove Weld Vent Pipe; dated
May 24, 2004
Liquid Penetrant Examination Record, Welds WC-E109-1A, 8A,13A, 15A, 17A, 22A,
33A; dated May 29, 2004
Westinghouse Report - Kewaunee Unit 1 Replacement Vessel Head Inspection Final
Report; dated June 17, 2004
J-Groove Weld Eddy Current Report Sheets; dated May 17-31, 2004
Radiographic Examination Records, Welds No. WC-J202-1A, 2A, 3A, 4A & 5A; dated
October 29, 2003
Ultrasonic Examination Record, Weld No. WC-J202-1A; dated October 30, 2003
Ultrasonic Examination Record, Latch Housing NKM806A; dated March 18, 2003
Ultrasonic Examination Record, Latch Housing NKM806A; dated March 27, 2003
Ultrasonic Examination Record, Closure Head Forging; dated April 9, 2003
Magnetic Particle Examination Record, Closure Head Forging; dated March 26, & 27,
2003
Radiographic Film Records:
Radiograph KEN-CRDM-WC-E110-34A; Instrument Port Head Adaptor to Adaptor
Attachment
20
Radiograph KEN-CRDM-WC-E114-9A; Spare CRDM Head Adapter to Extension Pipe
Radiograph KEN-RVCH-WC-E116-9A; Closure Cap to Extension Pipe Weld
Radiograph KEN-RVCH-WC-J009-3A; Rod Travel Housing to Latch Housing Weld
Radiograph KEN-RVCH-WC-J009-28A; Rod Travel Housing to Latch Housing Weld
Radiograph KEN-CRDM-WC-J202-3A; CRDM Head Adaptor to Latch Housing Weld
Radiograph KEN-CRDM-WC-J202-28A; CRDM Head Adaptor to Latch Housing Weld
Other Documents:
MHI Specification No. L3-01AA409; Standard Material Purchase Specification for Head
Adaptor Material (SB167 UNS N06690); Revision 4
Westinghouse Electric Co. Specification No. 676413; General Reactor Vessel
Specification; Revision 1
MHI Purchase Specification No. KCE-20020111; Stainless Steel Forging for Pressure
Vessel (ASME SA 182 Gr F316); Revision 2
Sumitomo Metal Industries LTD Certificates Nos. ONNC9498, ONNC9499, ONNC9503,
ONNC9505, ONNC9506, ONNC9507; dated May 28, 2003
Reactor Vessel Head Design Specification No. 418A75; Revision 0; and No. 414A84;
Revision 3
PO. No. P015276; Revisions 0 through 8
Calculation No. CN-RCDA-04-20; Nuclear Management Company Kewaunee RRVCH
ASME Section XI Code Reconciliation; Revision 0.
Letter, from Westinghouse to Nuclear Management Co.; dated May 2, 2003
Manufacturing Specification No. -7474-10; Closure Head Forging; Revision 2
Heat Treatment Strip Chart for Reactor Vessel Closure Head; No.03-518; dated
March 13, 2003
Heat Treatment Strip Chart for Reactor Vessel Closure Head, No.03-001; dated
January 16, 2003
Heat Treatment Strip Chart for Reactor Vessel Closure Head; No.03-569; dated
March 24, 2003
2033-9; Record of Quenching and Tempering- Closure Head Archive Sample; dated
March 14, 2003
2033-1-11; Record of Postweld Heat Treatment-Closure Head Archive Sample; dated
March 25, 2003
2033-1.3; Record of Normalizing and tempering-Closure Head Archive Sample; dated
January 7, 2003
MHI Document No. -7474-20; Quality Plan for Closure Head Forging; Revision 3
Reactor Head Replacement Project Guidelines-Fabrication Plan; dated June 29, 2004
Reactor Head Replacement Project Oversight Plan; Revision 2
Fabrication Process Sheets for Latch Housings Activities; April through July of 2003
Fabrication Process Sheets for CRDM Head Adaptor Activities; July through August of
2003
Fabrication Process Sheets for Spare CRDM Head Adaptor Flanges; July through
August of 2003
Fabrication Process Sheets for Instrument Port Head Adaptor Flange Activities; July
through September of 2003
Fabrication Process Sheets for the Reactor Vessel Closure Head Activities; July through
October of 2003
Attachment
21
Technical Specification - Design, Fabrication, and Installation of Replacement Reactor
Vessel Closure Heads; Revision 4
Record of Dimensional Inspection and Visual Examination; dated April 8, 2003
Record of Markings Heat Number of Closure Forging 02D973-1-1Test Coupons; dated
April 10, 2003
Subcontractor Corrective Action Notices:
MHI-03-008; dated August 4, 2003
MHI-03-010; dated August 22, 2003
MHI-03-022; dated September 24, 2003
MHI-03-023; dated September 26, 2003
Welding Procedures and Procedure Qualifications:
WPS Es0-3-5N; dated December 11, 2002
WPS Es0-3-6N; dated February 11, 2003
WPS A0-3-4N; dated December 11, 2002
WPS TO-3-4N; dated July 9, 2003
WPS A3.3-1N; dated January 16, 2003
WPS TA-3.43-11N; dated March 11, 2003
WPS TaTb-3.43-11N; dated February 3, 2004
PQR RE303V3; dated May 18, 1998
PQR RE303V4; dated May 18, 1998
PQR RE 03m1; dated December 6, 1991
PQR RE 03m2; dated December 6, 1991
PQR RE 03m3; dated November 7, 1991
PQR RT0m5; dated April 11, 1987
PQR RA0TaTa343R1; dated June 9, 2003
PQR RT 843m10; dated June 9, 2003
Weld Repair Records:
WC-E103-5, 2601-RVH-10A-R-1-R0-5; dated September 29,2003
WC-E109-3A/35A, 2601-RVH-10F-R4-39AC; dated May 20, 2004
WC-E109-35A, 2601-RVH-10F-R4-39AI; dated May 21, 2004
WC-E109-2, 2601-RVH-10F-R1-R0-9; dated May 29, 2004
WC-E109-1A, 2601-RVH-10F-R1-R0-9; dated May 29, 2004
WC-E109-8A, 2601-RVH-10F-R1-R0-9; dated May 29, 2004
WC-E109-13A, 2601-RVH-10F-R1-R0-9; dated May 29, 2004
WC-E109-15A, 2601-RVH-10F-R1-R0-9; dated May 29, 2004
WC-E109-17A, 2601-RVH-10F-R1-R0-9; dated May 29, 2004
WC-E109-22A, 2601-RVH-10F-R1-R0-9; dated May 29, 2004
WC-E109-33A, 2601-RVH-10F-R1-R0-9; dated May 29, 2004
Attachment
22
Welder Qualification Records for Weld Repairs:
B285, Qualification Record TW-6h F6; dated June 6, 2000
B304, Qualification Record TW-6h F6; dated June 6, 2000
B320, Qualification Record TW-3r F-43a; dated October 27, 2003
B275, Qualification Record TW-3r F-43; dated August 29, 1997
Condition Reports Initiated for NRC Identified Issues
CAP 023477; Certified Design Specification 414A84 Revision 3 Inadequacy; dated
October, 21, 2004
CAP 023040; Scaffolding too close to safety related equipment; dated October 6, 2004
CAP 023062; NRC Questions Shutdown Safety Assessment Orange Condition;
October 7, 2004
CAP 023228, 023235; NRC Questions equipment protection guidance;
October 13, 2004
CAP 023388; Oil in the Diesel Generator Room without permit and in excess of FPPA
values; dated October 19, 2004
CAP 023418; Materials found above the Sprinkler Line in the Working Materials Storage
Area; dated October 20, 2004
CAP 023428; Lube Oil improperly stored in 'A EDG room; October 20, 2004
CAP 023478; Combustibles found stored on cabinet in AX-32; dated October 21, 2004
CAP 023479; Potential Hazards not identified in Fire Area Strategies; dated October 21,
2004
CAP 023480; Improper storage of combustible gas cylinders; dated October 21, 2004
CAP 023483; Inadequate Corrective Action to CAP 16329; dated October 22, 2004
CAP 023501; Verification of Fire Area Strategies to FPPA; dated October 23, 2004
CAP 024553; Flammable gas cylinders found stored in AX-23B; dated December 14,
2004
CAP 023512; SFP Pump A motor oil leak; October 23, 2004
CAP 023582; CAP 023274 Reportability basis statement is incorrect; October 26, 2004
CAP 023606; CAP apparently not written for an instrument failure;October 27, 2004
CAP 023621; SRI questions spacings in Emergency Recirc Sump; October 27, 2004
CAP 023679; Containment Sump B Requires Cleaning; October 29, 2004
CAP 023771; Potential Non-Conformance With Containment Sump B;
November 2, 2004
CAP 023787; Cold Weather Operations Preps; November 3, 2004
CAP 023797; Flammable Materials Storage Cabinet Left Open; November 3, 2004
CAP 023814; Annulus Area Review For Adverse Weather; November 4, 2004
CAP 023816; Containment Sump Inspection Criteria Unclear; November 4, 2004
CAP 023839; Screws Missing On Diamond Plate In SW/CW Screen House;
November 5, 2004
CAP 023840; Containment Sump B Epoxy Coating; November 5, 2004
CAP 023908; Containment Closure Problem Encountered; November 9, 2004
CAP 023950; Containment Hatch Closure Interference; November 11, 2004
CAP 024365; Turbine Building flooding concern with AFW trench; December 1, 2004
Attachment
23
LIST OF ACRONYMS USED
Agencywide Documents Access and Management System
Atomic Energy Commission
Action Request
CA
Corrective Action
Corrective Action Program
CFR
Code of Federal Regulations
CR
Condition Report
Division of Reactor Projects
Division of Reactor Safety
Final Safety Analysis Report
IMC
Inspection Manual Chapter
KNPP
Kewaunee Nuclear Power Plant
kV
kilovolt
LER
Licensee Event Report
Loss of Coolant Accident
Licensed Operator Requalification
Non-Cited Violation
Nuclear Management Company
NRC
Nuclear Regulatory Commission
Public Availability Records
Pre-Fire Plan
Performance Indicator
Radiologically Controlled Area
Reactor Coolant Pump
Reactor Operator
Reactor Oversight Process
Systematic Approach to Training
Significance Determination Process
Spent Fuel Pool
Safety Injection
Senior Reactor Operator
Training Advisory Committee
TI
Temporary Instruction
TS
Technical Specification
Training Advisory Committee
Thermoluminescence Dosimeter
Updated Safety Analysis Report
Vendor Technical Information Program
Attachment
24
Volume Control Tank
Work Order
WPS
Wisconsin Public Service