ML051300633
| ML051300633 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 05/10/2005 |
| From: | Burgess B NRC/RGN-III/DRP/RPB2 |
| To: | Crane C Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-05-002 | |
| Download: ML051300633 (85) | |
See also: IR 05000374/2005002
Text
May 10, 2005
Mr. Christopher M. Crane
President and Chief Nuclear Officer
Exelon Nuclear
Exelon Generation Company, LLC
4300 Winfield Road
Warrenville, IL 60555
SUBJECT: LASALLE COUNTY STATION, UNITS 1 AND 2
NRC INTEGRATED INSPECTION REPORT 05000373/2005002;
Dear Mr. Crane:
On March 31, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated
inspection at your LaSalle County Station, Units 1 and 2. The enclosed report documents the
results of this inspection discussed on April 5, 2005, with the Site Vice President, Ms. Susan
Landahl, and other members of your staff.
The inspection examined activities conducted under your license as they related to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, four NRC-identified and three self-revealed findings of
very low safety significance were identified. All of these findings also involved violations of NRC
requirements. However, because the findings associated with these violations were of very low
safety significance and because the issues were entered into the licensees corrective action
program, the NRC is treating these issues as Non-Cited Violations in accordance with
Section VI.A.1 of the NRCs Enforcement Policy. Additionally, two licensee identified violations
are listed in Section 4OA7 of this report.
If you contest the subject or severity of any Non-Cited Violation in this report, you should
provide a response within 30 days of the date of this inspection report, with the basis for your
denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington, 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 Inspectors Office at the LaSalle County Station.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter
and its enclosures 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/
Bruce L. Burgess, Chief
Branch 2
Division of Reactor Projects
Docket Nos.: 50-373; 50-374
Enclosure: Inspection Report 05000373/2005002; 05000374/2005002
w/Attachment: Supplemental Information
cc w/encl: Site Vice President - LaSalle County Station
LaSalle County Station Plant Manager
Regulatory Assurance Manager - LaSalle County Station
Chief Operating Officer
Senior Vice President - Nuclear Services
Senior Vice President - Mid-West Regional
Operating Group
Vice President - Mid-West Operations Support
Vice President - Licensing and Regulatory Affairs
Director Licensing - Mid-West Regional
Operating Group
Manager Licensing - Clinton and LaSalle
Senior Counsel, Nuclear, Mid-West Regional
Operating Group
Document Control Desk - Licensing
Assistant Attorney General
Illinois Department of Nuclear Safety
State Liaison Officer
Chairman, Illinois Commerce Commission
DOCUMENT NAME: E:\Filenet\ML051300633.wpd
To receive a copy of this document, indicate in the box:"C" = Copy without enclosure "E"= Copy with enclosure"N"= No copy
OFFICE RIII N RIII RIII RIII
NAME BBurgess/sls
DATE 05/10/05 05/ /05 05/ /05 05/ /05
OFFICIAL RECORD COPY
ADAMS Distribution:
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RidsNrrDipmIipb
GEG
KGO
CAA1
C. Pederson, DRS (hard copy - IRs only)
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ROPreports@nrc.gov (inspection reports, final SDP letters, any letter with an IR number)
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-373; 50-374
Report No: 05000373/2005002; 05000374/2005002
Licensee: Exelon Generation Company, LLC
Facility: LaSalle County Station, Units 1 and 2
Location: 2601 N. 21st Road
Marseilles, IL 61341
Dates: January 1 through March 31, 2005
Inspectors: D. Kimble, Senior Resident Inspector
D. Eskins, Resident Inspector
A. Klett, Engineering Inspector
D. Melendez-Colon, Reactor Engineer
M. Mitchell, Radiation Protection Specialist
J. Neurauter, Engineering Inspector
T. Ploski, Senior Emergency Preparedness Inspector
R. Walton, Operator Licensing Examiner
J. Yesinowski, Illinois Dept. of Emergency Management
Approved by: Bruce L. Burgess, Chief
Branch 2
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1. REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R01 Adverse Weather Protection (71111.01) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R04 Equipment Alignment (71111.04) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1R05 Fire Protection (71111.05) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R08 Inservice Inspection (ISI) Activities (71111.08) . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R11 Licensed Operator Requalification Program (71111.11) . . . . . . . . . . . . . . . . . . 8
1R12 Maintenance Effectiveness (71111.12) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
1R13 Maintenance Risk Assessments and Emergent Work Evaluation (71111.13) . . 9
1R14 Operator Performance During Non-Routine Plant Evolutions and Events
(71111.14) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R15 Operability Evaluations (71111.15) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
1R16 Operator Workarounds (71111.16) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R17 Permanent Plant Modifications (71111.17) . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R19 Post Maintenance Testing (71111.19) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R20 Outage Activities (71111.20) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
1R22 Surveillance Testing (71111.22) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
1R23 Temporary Plant Modifications (71111.23) . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
1EP2 Alert and Notification System (ANS) Testing (71114.02) . . . . . . . . . . . . . . . . . 24
1EP3 Emergency Response Organization (ERO) Augmentation Testing (71114.03) 24
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies
(71114.05) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
2. RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
2OS1 Access Control to Radiologically Significant Areas (71121.01) . . . . . . . . . . . . 25
2OS2 As Low As Is Reasonably Achievable Planning And Controls (ALARA)
(71121.02) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
4. OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
4OA1 Performance Indicator Verification (71151) . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
4OA2 Identification and Resolution of Problems (71152) . . . . . . . . . . . . . . . . . . . . . 35
4OA3 Event Followup (71153) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
4OA4 Cross-Cutting Aspects of Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
4OA5 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
4OA6 Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
4OA7 Licensee Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
ATTACHMENT: Supplemental Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Enclosure
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Enclosure
SUMMARY OF FINDINGS
IR 05000373/2005002, 05000374/2005002; 01/01/2005 - 03/31/2005; LaSalle County Station,
Units 1 & 2; Fire Protection, Maintenance Risk Assessments and Emergent Work Control,
Post-Maintenance Testing, Access Control to Radiologically Significant Areas, and Identification
and Resolution of Problems Report.
The inspection was conducted by both resident and regional inspectors. The report covers a
3-month period of baseline resident inspection, and announced baseline inspections in
emergency preparedness, radiation protection, and of the inservice inspection program. Seven
Green findings and seven associated non-cited violations (NCVs) were identified. The
significance of most findings is indicated by their color (Green, White, Yellow, Red) using NRC
Inspection Manual Chapter (IMC) 0609 Significance Determination Process (SDP). Findings
for which the SDP does not apply may be "Green," or be assigned a severity level after NRC
management review. The NRC's 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-Revealing Findings
Cornerstone: Initiating Events
- Green. A finding of very low safety significance was self-revealed when sparks
from hot work associated with the cutting of a 20-inch pipe in the 2B residual
heat removal (RHR) corner room on February 16, 2005, ignited a small pile of
absorbent cleaning material in the room. An associated NCV was also identified
against Technical Specification 5.4.1(c) for failure to follow the existing plant fire
protection procedure related to hot work and ignition control.
The performance deficiency, identified during review of the event, involved two
examples where licensee personnel failed to properly implement the established
plant procedure governing hot work and ignition control. The finding was of
more than minor significance in that it had a direct impact on the cornerstone
objective. Specifically, the licensees performance deficiencies were directly
responsible for an actual Class A fire in the 2B RHR corner room on
February 16, 2005. Because the finding involved Unit 2 in a cold shutdown
condition, the inspectors determined it to be of very low safety significance
(Green) and within the licensees response band. Corrective actions completed
by the licensee include: focused coaching sessions with superintendents and
general foremen of hot work personnel; meetings between the stations Fire
Marshal and contractor supervision to discuss hot work issues; and focused
coaching sessions with fire watch personnel by contractor management
conveying the message that the fire watch is ultimately responsible for the work
location being and remaining in compliance with fire safety standards. The
finding was determined to involve the cross-cutting aspect of human
performance. (Sections 1R05.2 and 4OA4)
1 Enclosure
- Green. The inspectors identified a finding of very low safety significance and an
associated NCV during review of corrective actions associated with a small fire in
the 2B RHR corner room on February 16, 2005. The inspectors determined that
the licensee had, during several opportunities, failed to take timely and effective
corrective actions with respect to ignition control for hot work. This failure was
determined by the inspectors to be contrary to the requirements of 10 CFR 50,
Appendix B, Criterion XVI, "Corrective Action."
In reviewing corrective actions for 2B RHR corner room fire, the inspectors
identified a performance deficiency regarding inadequate corrective actions
taken to control hot work activities. The inspectors determined that the finding
was of more than minor significance in that it had a direct impact on an objective
for the Initiating Event Cornerstone. The inspectors determined that the finding
impacted minimally on the licensees capability to reach and maintain cold
shutdown conditions. Therefore, this finding had very low safety significance
(Green) and was within the licensee's response band. Additional corrective
actions planned by the licensee include a comprehensive common cause
analysis to determine whether or not generic fire protection programmatic
weaknesses exist. (Section 4OA2.1)
- Green. The inspectors identified a finding of very low safety significance and an
associated NCV during a review of the licensees assessment and management
of the risk affiliated with maintenance on the 1A circulating water (CW) pump.
The inspectors review revealed that the licensee had failed to recognize and
effectively manage the risk associated with a meter replacement. The meter
was in a circuit that was common to both the 1A CW pump, which was
undergoing planned maintenance, and the 1C CW pump, which was in service.
This failure to effectively assess and manage maintenance risk was determined
by the inspectors to be contrary to the requirements of 10 CFR 50.65(a)(4).
The performance deficiency with this issue was a failure on the part of the
licensee to properly assess and manage the increase in risk from a planned
maintenance evolution. The finding was of more than minor significance in that it
had a direct impact on a Initiating Event Cornerstone objective. Specifically, the
licensees failure to properly assess and manage the increase in risk resulted in
a plant transient that challenged the on-watch Operations crew. The inspectors
determined this finding to be of very low safety significance (Green) because the
finding did not contribute to both the likelihood of a transient and the likelihood
that mitigation equipment or functions would not be available. Corrective actions
completed by the licensee include: training to enhance worker proficiency at
performing maintenance risk assessments on energized equipment, assessment
of the existing production risk evaluation sheet used by work planners to
determine if additional clarifications are required, discussion of this type of task
at weekly work management meetings, reinforcement of Operations role in
reviewing work on production risk systems, and evaluation of whether or not
additional actions are required during clearance order preparations to preclude
this type of event. The finding was determined to involve the cross-cutting
aspect of human performance. (Sections 1R13.2 and 4OA4)
2 Enclosure
Cornerstone: Mitigating Systems
- Green. The inspectors identified a finding of very low safety significance and an
associated NCV during a review of the licensees assessment and management
of the risk affiliated with the cycling of the 1DG032 manual gate valve. The gate
valve was cycled during the performance of a scheduled 0 emergency diesel
generator (EDG) auxiliaries inservice test on December 30, 2004. The
inspectors review revealed that the licensee had failed to recognize and
effectively manage the risk associated with the operation of this valve. This
valve was part of a group of manual gate valves located in essential service
water systems that were known to be highly susceptible to disc/stem separation.
This failure to effectively assess and manage the activitys risk was determined
by the inspectors to be contrary to the requirements of 10 CFR 50.65(a)(4).
The identified performance deficiency with this finding was a failure on the part of
the licensee to have accurately assessed and properly managed the risk
associated with the cycling of the 1DG032 manual gate valve. The finding was
of more than minor significance in that it had a direct impact on an objective of
the Mitigating Systems cornerstone. Specifically, the licensees failure to
properly assess and effectively manage the risk associated with the 1DG032
valve cycling evolution resulted in the interruption of supporting cooling water
flow to Unit 1 Division 1 emergency core cooling system (ECCS) components,
rendering these components inoperable and unavailable. Because the finding
impacted only a single Division of the units ECCS; did not represent the loss of
an entire systems safety function; did not result in a Technical Specification
allowed outage time being exceeded; and the finding was not related to external
events such as fire, flooding, or adverse weather; the inspectors concluded that
the safety significance of this issue was very low (Green). Corrective actions
completed by the licensee include: hanging tags on susceptible valves to warn
personnel of the potential for stem/disc separation; validation of all essential
service water valves susceptible to stem/disc separation and providing a listing
of these components to plant operations; revision of applicable operating
procedures to include a precaution that identifies the valves that are susceptible
to stem/disc separation, and a requirement to verify the applicability of valves
prior to operation. (Section 1R13.3)
- Green. A finding of very low safety significance was self-revealed when changes
implemented by a modification to the Unit 2 125 volt direct current (Vdc) charger
system were not appropriately incorporated into operational procedures. This
procedural deficiency resulted in an under-voltage condition during an attempt to
swap in-service chargers. An associated NCV against the requirements of
10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
was also identified.
The identified performance deficiency was the failure of the licensee to
incorporate relevant design information concerning the metering circuitry of a
newly installed battery charger into the appropriate operating procedures. The
finding was of more than minor significance in that it had a direct impact on the
3 Enclosure
MS cornerstone objective. Specifically, the procedural deficiency, and lack of
any formal training regarding the metering circuitry, contributed to a low voltage
condition on the Unit 2 Division 1 125 Vdc system. The low voltage resulted in
the Unit 2 Division 1 125 Vdc system being rendered inoperable for about 23
minutes. Because the finding involved the loss of only one train of safety related
equipment and the loss was for less than the Technical Specification allowed
outage time, the inspectors determined it to be of very low safety significance
(Green) and within the licensees response band. Corrective actions planned
and completed by the licensee include: revision of applicable operating
procedures; training for operations personnel on new charger procedures; and
planned training to enhance operator knowledge regarding the metering circuitry
and the differences between various battery chargers. (Section 1R19.2)
- Green. A finding of very low safety significance was identified by the inspectors.
The licensee had failed during prior opportunities to fully evaluate the nature of
the problem leading to various emergency diesel generator (EDG) reverse power
trips. The most recent of these events were a reverse power trip of the 2B EDG
on August 18, 2004, for which no root cause was ever determined, and a
subsequent reverse power trip of the 2A EDG that occurred on December
7, 2004. An associated Non-Cited Violation (NCV) of 10 CFR 50, Appendix B,
Criterion XVI, "Corrective Action," was also identified by the inspectors.
The performance deficiency was determined to be a failure on the part of the
licensees staff to fully evaluate a long standing issue with EDG reverse power
trip. An evaluation in response to an event, as recent as August 18, 2004, failed
to give sufficient priority to identified corrective actions in a manner that would
preclude the latest occurrence, a reverse power trip of the 2A EDG on
December 7, 2004. The finding was of more than minor significance in that it
had a direct impact on the cornerstone objective. Specifically, the inspectors
concluded that the licensee's performance deficiency was responsible for the
reverse power trip of the 2A EDG on December 7, 2004, which caused the EDG
to be unavailable for an additional 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br />. Because the finding involved the
loss of only one train of safety related equipment and the loss was for less than
the Technical Specification allowed outage time, the inspectors determined it to
be of very low safety significance (Green) and within the licensee's response
band. Corrective actions planned and completed by the licensee include:
establishment of a less restrictive EDG load limit to allow opening the EDG
output breaker when the load is less than approximately 500 kW; additional
training for licensed operators in the areas of EDG theory and operation and the
effects of reverse power conditions on diesel generators; and revision of
simulator modeling for EDGs to more accurately reflect actual plant performance
for reverse power trips. (Section 4OA2.2)
Cornerstone: Occupational Radiation Safety
- Green. A finding of very low safety significance was self-revealed when an
electrician improperly entered a high radiation area (HRA) in the radiation
controlled area (RCA) (the Unit 2 drywell) that was posted as a HRA. This
4 Enclosure
occurrence was revealed when he exited the RCA and the electronic dosimeter
check-out was alerted that a dose rate alarm had occurred during the entry,
revealing that the individual had signed on to the wrong radiation work permit
(RWP).
The cause of the error was a failure to assure through self-checking that each
entry to the electronic RWP sign-in is made using the correct RWP. The finding,
under the Occupational Radiation Safety Cornerstone, does not involve the
application of traditional enforcement because it did not result in actual safety
consequences or potential to impact the NRCs regulatory function, and was not
the result of any willful actions. The finding was more than minor as it involves
the failure of the licensee to adhere to procedures to monitor and control
radiation exposure, a key attribute under the objective of the radiation safety
cornerstone to ensure adequate protection of worker health and safety from
exposure to radiation. The finding is of very low safety significance because the
individual was using an electronic dosimeter that alarms to warn workers of
higher than expected dose rates or accumulated dose. The issue constituted a
Non-Cited Violation of Technical Specification 5.7.1, which requires that access
to, and activities in, each HRA with dose rates not exceeding 1.0 rem per hour at
30 centimeters from the radiation source be controlled by means of a RWP that
includes specification of radiation dose rates in the immediate work area and
other appropriate radiation protection equipment and measures. Immediate
corrective actions included locking the individual out of the RCA and initiation of
an investigation. Additionally, all site personnel were notified of this event
through a station safety alert. The primary cause of the finding was related to
the cross-cutting area of human performance. (Sections 2OS1.4 and 4OA4)
B. Licensee-Identified Violations
Violations of very low safety significance that were identified by the licensee have been
reviewed by inspectors. Corrective actions planned or taken by the licensee have been
entered into the licensees corrective action program. These violations and corrective
action tracking numbers are listed in Section 4OA7 of this report.
5 Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1
The unit began the inspection period operating at full power. On February 5, 2005, power was
reduced to approximately 65 percent to permit a control rod sequence exchange and control
rod surveillance testing. The unit returned to operation at full power on February 6, 2005, and
continued operating at or near full power for the remainder of the inspection period.
Unit 2
The unit began the inspection period operating at full power. On January 8, 2005, power was
reduced to approximately 62 percent for a control rod pattern adjustment. Operation at full
power was resumed on January 10, 2005. On February 7, 2005, the unit shut down for
refueling outage L2R10. Unit 2 Cycle 11 achieved initial criticality following L2R10 on
March 15, 2005, with full power being attained on March 18, 2005. On March 22, 2005, power
was reduced briefly to approximately 65 percent to permit a control rod sequence exchange
and control rod surveillance testing. The unit returned to full power operation later that same
day, and continued operating at or near full power for the remainder of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
1R01 Adverse Weather (71111.01)
Review of Site Specific Weather Condition - Tornado Warning
a. Inspection Scope
The inspectors performed an assessment of the licensees preparations for adverse
weather, including conditions that could lead to loss of off-site power and other
conditions that could result from high winds or tornado-generated missiles. The
licensees procedures and preparations during a tornado warning in LaSalle County on
March 30, 2005, were reviewed by the inspectors and were verified to be adequate.
During the inspection, the inspectors focused on plant specific design features and the
licensees procedures used to respond to specified adverse weather conditions.
Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)
and performance requirements for systems selected for inspection, and verified that
operator actions were appropriate as specified by plant specific procedures.
This review constituted a single inspection sample.
1 Enclosure
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment (71111.04)
.1 Semiannual Complete System Alignment Verification
a. Inspection Scope
Due to the systems risk significance, the inspectors selected the Unit 1 core standby
cooling system (CSCS) for a complete system alignment verification. The inspectors
walked down the system to verify mechanical and electrical equipment lineups,
component labeling, component lubrication, component and equipment cooling, hangers
and supports, operability of support systems, and to ensure that ancillary equipment or
debris did not interfere with equipment operation.
The inspectors review of CSCS alignment constituted a single inspection sample.
b. Findings
No findings of significance were identified.
.2 Quarterly Partial System Alignment Verifications
a. Inspection Scope
The inspectors performed partial alignment verifications on the following equipment
trains to verify operability and proper equipment lineup. These systems were selected
based upon risk significance, plant configuration, system work or testing, or inoperable
or degraded conditions.
- Unit 2 fuel pool cooling system while unit fuel pools were cross connected
- Unit 2 B residual heat removal low pressure core spray system
- Unit 2 C residual heat removal low pressure core spray system
The inspectors verified the position of critical redundant equipment and looked for any
discrepancies between the existing equipment lineups and the required lineups.
These partial equipment alignment verifications constituted three inspection samples.
b. Findings
No findings of significance were identified.
2 Enclosure
1R05 Fire Protection (71111.05)
.1 Quarterly Fire Protection Zone Inspections
a. Inspection Scope
To identify potential fire protection issues, the inspectors conducted field observations in
the following risk significant areas. These areas were selected because of the systems,
structures, or components designated as important to reactor safety that were located
therein.
- Fire Zone 4E1, Unit 1 auxiliary equipment room
- Fire Zone 4E3, Unit 1 Division 2 essential switchgear room
- Fire Zone 4F1, Unit 1 Division 1 essential switchgear room
- Fire Zone 4F2, Unit 2 Division 1 electrical switchgear room
- Fire Zone 8B1, Unit 2 Division 3 emergency diesel generator room
- Fire Zone 8B2, Unit 2 Division 2 emergency diesel generator room
- Fire Zone 8C1, Unit 2 Division 3 emergency diesel generator fuel storage tank
room
- Fire Zone 8C3, Unit 2 Division 3 emergency diesel generator cooling water pump
room
- Unit 2 emergency diesel generator corridor
The inspectors reviewed the control of transient combustibles and ignition sources, fire
detection equipment, manual suppression capabilities, passive suppression capabilities,
automatic suppression capabilities, barriers to fire propagation, and any contingency fire
watches that were in effect.
These quarterly fire protection inspections constituted nine inspection samples.
b. Findings
No findings of significance were identified.
.2 2B Residual Heat Removal (RHR) Corner Room Fire
a. Inspection Scope
The inspectors followed up on a small Class A fire that occurred in the 2B RHR corner
room as a result of hot work on February 16, 2005. The inspectors reviewed the control
of transient combustibles and ignition sources, fire detection equipment, manual
suppression capabilities, passive suppression capabilities, automatic suppression
capabilities, barriers to fire propagation, and any contingency fire watches that were in
effect. In addition, the inspectors reviewed the licensees apparent cause evaluation
(ACE) for the event.
This review constituted a single inspection sample.
3 Enclosure
b. Findings
Introduction
A finding of very low safety significance (Green) was self-revealed when sparks from hot
work associated with the cutting of a 20-inch pipe in the 2B RHR corner room ignited a
small pile of absorbent cleaning material in the room. A Non-Cited Violation (NCV) of
Technical Specification 5.4.1(c) for failure to follow the existing plant fire protection
procedure related to hot work and ignition control was also identified.
A second finding and NCV associated with this event are described in Section 4OA2.1
of this report.
Description
On February 16, 2005, at approximately 2:30 p.m., work was in progress in the 2B RHR
corner room to demolish a section of pipe that was slated for removal as part of an
approved permanent plant modification. The work involved cutting a vertical run of
20-inch diameter pipe into sections that were approximately 1 foot in length to facilitate
ease of removal. A single fire watch was assigned to the area where the cutting was
taking place. Fire blanketing was placed in the area of the hot work, with additional
material surrounding the floor piping penetration to prevent sparks from falling through
the penetration. This fire blanket extended outward for approximately 8 feet from the
work. During the course of the work, some of the sparks generated by the pipe cutting
activities were thrown past the fire blanket and fell through open floor grating to the
694' elevation below.
At some point following lunch, cleaning material was staged on the 694' elevation below
the area where the hot work was in progress. When interviewed as part of the
licensees ACE, the fire watch stated that he was not aware of the introduction of this
combustible material to this area. Sparks that fell from the hot work above ignited a
small Class A fire in this material. A laborer in the area detected the fire and attempted
to extinguish it by stepping on the flames. When this was not successful, a mop was
used in an attempt to smother the flames. When this action, too, proved ineffective, the
laborer notified the fire watch on the level above, who extinguished the fire with a dry
chemical fire extinguisher. The control room was notified of the fire by the personnel
involved in the 2B RHR corner room.
Unrelated to the actual fire itself, a problem was encountered with the dry chemical fire
extinguisher used by the fire watch to combat the fire. In addition to being discharged
from the nozzle as expected, dry chemical extinguishing agent was observed to emit
from underneath the cap of the extinguisher. As noted above, despite this malfunction,
the fire watch was able to use the extinguisher to successfully combat the fire. An
investigation by the licensee subsequently determined that the malfunction was the
result of a missing gasket normally installed under the fire extinguisher cap.
4 Enclosure
Analysis
The inspectors determined that there was a licensee performance deficiency associated
with the fire blanket coverage provided for the job. Specifically, the coverage was
inadequate in that it did not fully contain all the sparks being generated from the cutting
activity, and was not in compliance with the licensees established procedure governing
hot work ignition controls. Procedure OP-MW-201-004, Fire Prevention for Hot Work,
Section 4.2, Fire Prevention Precautions, required fire blanket coverage out to 35 feet
from the work location. In this event, the fire blanket coverage went out a mere 8 feet.
This lack of adequate fire blanket coverage was, in part, responsible for the sparks from
the hot work reaching the open floor grating and falling to the 694' elevation below.
In addition, a second performance deficiency associated with the duties of the fire watch
was identified. Procedure OP-MW-201-004, Section 3.4.2, discussed the duties of the
fire watch, and required that each fire watch was responsible for stopping the hot work
in the event of any safety problems, such as sparks coming in contact with combustible
material, etc. At the time of the fire, the hot work in the 2B RHR corner room had been
in progress for three shifts. The fire watches assigned to the job had ample opportunity
to self-identify the spark hazard caused by the hot work and were required by procedure
to do so.
The objective of the Initiating Events Cornerstone of Reactor Safety is to limit the
likelihood of those events that upset plant stability and challenge critical safety functions
during shutdown as well as power operations. In accordance with NRC Inspection
Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue
Screening, the inspectors determined that the finding was of more than minor
significance in that it had a direct impact on this cornerstone objective. Specifically, one
of the key attributes associated with this cornerstone objective is protection against fires,
and the inspectors determined that the licensees performance deficiencies were directly
responsible for an actual Class A fire in the 2B RHR corner room.
The inspectors determined that the finding could be evaluated using the SDP in
accordance with IMC 0609, Significance Determination Process, and conducted a
Phase 1 characterization and initial screening. Because the finding was associated with
fire protection, this was accomplished using IMC 0609, Appendix F, Attachment 1, Fire
Protection SDP Phase 1 Worksheet. Based on the size and location of the fire, the
inspectors concluded it could only plausibly affect Unit 2, which was in cold shutdown.
As a result, the inspectors determined that the finding only pertained to the ability to
reach and maintain cold shutdown conditions, and was, therefore, of very low safety
significance (Green) and within the licensees response band. Because the finding
involved the cross-cutting aspect of human performance, it is also noted in
Section 4OA4, Cross-Cutting Aspects of Findings, in this report.
Enforcement
Technical Specification 5.4.1(c) requires that written procedures for the stations fire
protection program be established, implemented, and maintained. Contrary to this
requirement, on February 16, 2005, licensee personnel conducting hot work in the 2B
5 Enclosure
RHR corner room failed to implement the following provisions of OP-MW-201-004, Fire
Prevention for Hot Work, as specified:
- Section 4.2.1.4, Openings or cracks in walls, floors, or ducts within 35 feet of
the site shall be tightly covered to prevent the passage of sparks to adjacent
areas;
- Section 3.4.2, The Fire Watch is responsible for stopping the hot work in the
event of a safety problem (i.e., sparks coming in contact with combustible
material, faulty equipment, etc.).
The licensee had entered this fire into their corrective action program (CAP) as Issue
Report (IR) 302209. Similarly, the malfunction of the dry chemical fire extinguisher was
entered into the CAP as IR 302447. Corrective actions completed by the licensee
include: focused coaching sessions with superintendents and general foremen of
personnel performing hot work; meetings between the stations Fire Marshal and
contractor supervision to discuss hot work issues; and focused coaching sessions with
fire watch personnel by contractor management conveying the message that the fire
watch is ultimately responsible for the work location being and remaining in compliance
with fire safety standards. Because the licensee has entered the issue into their
corrective action program and the finding is of very low safety significance, this violation
of Technical Specification 5.4.1(c) is being treated as an NCV, consistent with
Section VI.A of the NRC Enforcement Policy. (NCV 05000374/2005002-01)
1R08 Inservice Inspection (ISI) Activities (71111.08)
Piping Systems ISI
a. Inspection Scope
From February 7 to February 9, 2005, and from February 28 to March 1, 2005,
inspectors conducted a review of the implementation of the licensees ISI program for
monitoring degradation of the reactor coolant system boundary and the risk significant
piping system boundaries for Unit 2. The inspectors selected the American Society of
Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI required
examinations and code components in order of risk priority as identified in
Section 71111.08-03 of NRC inspection procedure (IP) 71111.08, Inservice Inspection
Activities, based upon the ISI activities available for review during the onsite inspection
period.
(02.01.a and 02.01.b)
The inspectors conducted an on-site review of the following types of nondestructive
examination activities to evaluate compliance with the ASME Code Section XI and
Section V requirements and to verify that indications and defects (if present) were
dispositioned in accordance with the ASME Code Section XI requirements. Specifically,
the inspectors observed the following examination:
- Magnetic particle examination of residual heat removal system piping line
2RH40CB-16-inch restraint RH40-2877X lug welds. Two recordable indications
6 Enclosure
were identified and dispositioned in accordance with the ASME Code Section XI
requirements.
The inspectors performed a record review for the following examination:
- Ultrasonic examination of reactor pressure vessel nozzle to shell weld LCS-2-N2B.
No recordable indications were identified.
(02.01.c)
The inspectors reviewed examinations completed during the previous outage with
relevant/recordable conditions/indications that were accepted for continued service to
verify that the licensees acceptance was in accordance with Section XI of the ASME
Code. Specifically, the inspectors reviewed the following records:
- Five recordable indications found during ultrasonic examination of reactor
pressure vessel weld LCS-2-BH;
- Ten recordable indications found during ultrasonic examination of reactor
pressure vessel nozzle to shell weld LCS-2-N4D.
(02.01.d)
The inspectors reviewed pressure boundary welds for Code Class 1 or 2 systems which
were completed during the previous refueling outage, to verify that the welding
acceptance and preservice examinations (e.g., pressure testing and dye penetrant
tests) were performed in accordance with the ASME Code Sections III, V, IX, and XI
requirements. Specifically, the inspectors reviewed welds associated with the following
work activity:
- Penetrant examination of welds for replacement of double block valves
2E12-F325B/326B with single block valves.
(02.05)
The inspectors performed a review of piping system ISI related problems that were
identified by the licensee and entered into the CAP. The inspectors reviewed these
CAP documents to confirm that the licensee had appropriately described the scope of
the problems. Additionally, the inspectors review included confirmation that the
licensee had an appropriate threshold for identifying issues and had implemented
effective corrective actions. The inspectors evaluated the threshold for identifying
issues through interviews with licensee staff and review of licensee actions to
incorporate lessons learned from industry issues related to the ISI program. The
inspectors performed these reviews to ensure compliance with 10 CFR 50, Appendix B,
Criterion XVI, Corrective Action, requirements. The corrective action documents
reviewed by the inspectors are listed in the attachment to this report.
All the reviews discussed above constituted a single inspection sample.
7 Enclosure
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program (71111.11)
a. Inspection Scope
The inspectors observed a training crew during an evaluated simulator scenario and
reviewed licensed operator performance in mitigating the consequences of events. The
scenario included a scram condition that resulted from a loss of coolant accident
(LOCA). The training crews response to this casualty was complicated by a simulated
stuck open turbine bypass valve. Areas observed by the inspectors included: clarity
and formality of communications, timeliness of actions, prioritization of activities,
procedural adequacy and implementation, control board manipulations, managerial
oversight, emergency plan execution, and group dynamics. Additionally, the inspectors
observed the instructors critique and evaluation of the training crews performance.
This quarterly training observation constituted a single inspection sample.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
a. Inspection Scope
The inspectors reviewed the licensee's handling of performance issues and the
associated implementation of the Maintenance Rule (10 CFR 50.65) to evaluate
maintenance effectiveness for the Unit 1 and Unit 2 standby liquid control (SBLC)
systems. The systems were selected based on being designated as risk significant
under the Maintenance Rule and due to inspector-identified issues that potentially could
impact system work practices, reliability, or common cause failures.
The inspectors review included verification of the licensee's categorization of specific
issues, including evaluation of the performance criteria, appropriate work practices,
identification of common cause errors, extent of condition, and trending of key
parameters. Additionally, the inspectors reviewed the licensee's implementation of the
Maintenance Rule requirements, including a review of scoping, goal-setting,
performance monitoring, short-term and long-term corrective actions, functional failure
determinations associated with the condition reports reviewed, and current equipment
performance status.
This maintenance effectiveness review constituted a single inspection sample.
8 Enclosure
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
.1 Routine Quarterly Inspections
a. Inspection Scope
The inspectors reviewed and observed emergent work, preventive maintenance, or
planning for risk significant maintenance activities. The inspectors observed
maintenance or planning for the following activities or risk significant systems
undergoing scheduled or emergent maintenance:
- Water intrusion into Unit 1 core standby cooling system (CSCS) pump room
ventilation control panels;
- Unit 1 drywell floor drain sump alternate fill up rate monitor failure upscale
troubleshooting and repair;
- Unit 1 scram discharge volume 1/2 scram condition due to instrument failure;
- Unit 1 and Unit 2 Division 1 and 2 safeguards 4,160 Vac buses single point
vulnerability.
The inspectors also reviewed the licensee's evaluation of plant risk, risk management,
scheduling, and configuration control for these activities in coordination with other
scheduled risk significant work. The inspectors verified that the licensee's control of
activities considered assessment of baseline and cumulative risk, management of plant
configuration, control of maintenance, and external impacts on risk. In-plant activities
were reviewed to ensure that the risk assessment of maintenance or emergent work
was complete and adequate, and that the assessment included an evaluation of external
factors. Additionally, the inspectors verified that the licensee entered the appropriate
risk category for the evolutions.
These reviews constituted four inspection samples.
b. Findings
No findings of significance were identified.
.2 1C Circulating Water (CW) Pump Trip During Maintenance
a. Inspection Scope
The inspectors reviewed the licensees planning for work during a scheduled 1A CW
pump maintenance period. Among the items reviewed were the licensee's evaluation of
plant risk, risk management, scheduling, and configuration control for the scheduled
activities, and coordination with other scheduled risk significant work. The inspectors
verified that the licensees control of activities considered assessment of baseline and
cumulative risk, management of plant configuration, control of maintenance, and
9 Enclosure
external impacts on risk. Additionally, the inspectors verified that the licensee entered
the appropriate risk category for the planned maintenance tasks.
This review constituted a single inspection sample.
b. Findings
Introduction
The inspectors identified a finding of very low safety significance (Green) and an
associated Non-Cited Violation (NCV) during a review of the licensees assessment and
management of the risk affiliated with maintenance on the 1A circulating water (CW)
pump. The inspectors review revealed that the licensee had failed to recognize and
effectively manage the risk associated with a meter replacement in a circuit that was
common to both the 1A CW pump, which was undergoing planned maintenance, and
the in service 1C CW pump. This failure to effectively assess and manage maintenance
activity risk was determined by the inspectors to be contrary to the requirements of
Description
On January 4, 2005, at approximately 1:05 p.m., the 1C CW pump tripped. A planned
maintenance window for the 1A CW pump was in progress to allow plant electricians to
replace the 1A CW pumps elapsed run time meter. An investigation by the licensee
revealed that an actuation of the 1C CW pumps slip guard relay caused the trip. An
electrical short generated during the 1A CW pumps elapsed run time meter
replacement had caused the 1C CW pumps slip guard relay to actuate.
A licensee root cause review (RCR) of this event identified several human performance
issues. First, the work planner for the meter replacement task incorrectly evaluated
production risk when completing the stations production risk evaluation form for the
work package. Second, the electrical maintenance first-line supervisor did not correctly
perform the maintenance risk assessment for the task prior to executing the work. Third,
the craft electricians actually performing the meter replacement task caused an
electrical short that was the initiating event for the transient. Central to all of these
errors was the fact that an unidentified common metering circuitry existed between the
1A and 1C CW pumps. This unidentified circuit caused a short circuit during the 1A CW
pumps meter replacement to affect the running 1C CW pump. This common circuitry
had not been identified by the work planner or by the electrical maintenance first-line
supervisor during their respective risk assessments.
The trip of the 1C CW pump resulted in a slow loss of condenser vacuum, which
translated into an approximate 30 Mwe loss in generation. Ultimately, the licensee
reduced Unit 1 reactor power by approximately six percent in order to allow the
operating crew to more easily deal with the event and the recovery from it.
10 Enclosure
Analysis
The inspector-identified performance deficiency with this issue was the failure on the
part of various licensee staff members to accurately assess and properly manage the
risk associated with replacement of the 1A CW pumps elapsed run time meter. Upon
review of the event, the inspectors determined that sufficient information was available
to identify the common circuitry between the 1A and 1C CW pumps. Consequently, the
licensee should have had sufficient information to properly assess and manage the risk
associated with 1A CW pumps elapsed run time meter replacement. In interviews with
senior licensee staff members, the inspectors identified that had the vulnerability to the
running 1C CW pump been better understood, managers probably would not have
allowed the meter replacement to be performed with the unit on line, or, at a minimum,
would have ensured that more controls and oversight were in place during the evolution.
The objective of the Initiating Events Cornerstone of Reactor Safety is to limit the
likelihood of those events that upset plant stability and challenge critical safety functions
during shutdown as well as power operations. In accordance with NRC Inspection
Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue
Screening, the inspectors determined that the finding was of more than minor
significance in that it had a direct impact on this cornerstone objective. Specifically, the
licensees failure to properly assess and effectively manage the risk associated with the
1A CW pumps elapsed run time meter replacement resulted in a transient to the unit
that upset its stability and constituted an unwarranted operating challenge to the
on-watch control room crew.
The inspectors determined that the finding could be evaluated using the SDP in
accordance with IMC 0609, Significance Determination Process, and conducted a
Phase 1 characterization and initial screening. Because the finding did not contribute to
both the likelihood of a transient and the likelihood that mitigation equipment or
functions would not be available, the inspectors determined it to be of very low safety
significance (Green) and within the licensees response band. Because the finding
involves the cross-cutting aspect of human performance, it is also noted in Section
4OA4, Cross-Cutting Aspects of Findings, in this report.
Enforcement
As described in the SDP station-specific notebooks for LaSalle Units 1 and 2 and the
licensees Maintenance Rule Program, the CW pumps are risk-significant components.
Section (a)(4) of 10 CFR 50.65 states that before performing maintenance activities
(including but not limited to surveillance, post-maintenance testing, and corrective and
preventive maintenance), the licensee shall assess and manage the increase in risk that
may result from the proposed maintenance activities. Contrary to this requirement, the
licensee failed to properly assess and effectively manage the increase in risk associated
with the replacement of the 1A CW pumps elapsed run time meter.
The licensee had entered this issue into their corrective action program as IR 287541.
Corrective actions completed by the licensee included: administration of training to
enhance worker knowledge and proficiency at performing maintenance risk
assessments on energized equipment; assessment of the existing production risk
11 Enclosure
evaluation sheet used by work planners to determine if additional questions and
clarifications are required; discussion of this type of task at weekly work management
meetings; and reinforcement of the Operations role in reviewing work on production risk
systems. Because the licensee has entered the issue into their corrective action
program and the finding is of very low safety significance, this violation of
10 CFR 50.65(a)(4) is being treated as an NCV, consistent with Section VI.A of the NRC
Enforcement Policy. (NCV 05000373/2005002-02)
.3 Valve 1DG032 Disc/Stem Separation During Operation
a. Inspection Scope
The inspectors reviewed the planning associated with a scheduled 0 emergency diesel
generator (EDG) auxiliaries inservice test (IST) on December 30, 2004. Among the
items reviewed were the licensee's evaluation of plant risk, risk management,
scheduling, and configuration control for the activities performed,; and coordination with
other scheduled risk significant work. The inspectors verified that the licensees control
of activities considered assessment of baseline and cumulative risk, management of
plant configuration, control of maintenance, and external impacts on risk. Additionally,
the inspectors verified that the licensee entered the appropriate risk category for the
work performed.
This review constituted a single inspection sample.
b. Findings
Introduction
The inspectors identified a finding of very low safety significance (Green) and an
associated Non-Cited Violation (NCV) during a review of the licensees assessment and
management of the risk affiliated with the cycling of the 1DG032 manual gate valve
during the performance of a scheduled 0 EDG auxiliaries inservice test on
December 30, 2004. The inspectors review revealed that the licensee had failed to
recognize and effectively manage the risk associated with the operation of this valve.
This valve was part of a group of manual gate valves located in the plants essential
service water systems that were known to be highly susceptible to disc/stem separation.
This failure to effectively assess and manage the activitys risk was determined by the
inspectors to be contrary to the requirements of 10 CFR 50.65(a)(4).
Description
On December 30th, 2004, plant operators performed procedure LOS-DG-Q1, 0 Diesel
Generator Auxiliaries Inservice Test, Attachment A5, 0 Diesel Generator Cooling
Water Pump ASME Section XI Test. A pre-evolution briefing, held with two
non-licensed operators (NLOs) included direction that if indicated cooling water flows
were not within specification to return to the control room. The control room operators
would then provide additional briefings to the NLOs on actions contained in the
procedure intended to correct cooling water flow abnormalities.
12 Enclosure
Initial Unit 1 Division 1 cooling water flow rates were identified to be high and outside of
the procedures specified acceptance criteria. The on-watch Shift Manager was notified
of the condition and engineering contacted for assistance. Based on discussions
between engineering and operations personnel, it was determined that operators should
continue in accordance with LOS-DG-Q1, Attachment A5, in an attempt to correct the
out of specification cooling water flow. An additional NLO was assigned to assist with
these activities. A second pre-evolution briefing was held with the three NLOs, followed
by a briefing for the Unit 1 and Unit 2 operations control room crews. Items discussed
during these briefings included applicable Technical Specification Required Actions
(RAs) to be entered when specific valves were to be manipulated, the potential for
stem/disc separation, and the potential for EDG cooling water flow to be high, above
acceptable limits. Although operations personnel were not aware that the 1DG032 valve
was specifically susceptible to stem/disc separation, it was well known within the
licensees organization that similar type valves in this system have had a history of such
failures.
Valve 1DG032 controls flow through the northwest emergency core cooling system
(ECCS) corner room area cooler, the northeast ECCS corner room area cooler, and the
low pressure core spray (LPCS) motor cooler. Procedure LOS-DG-Q1 directed the
NLOs to cycle this valve as part of a sequence of steps intended to perform a flush of
system components in an attempt to restore cooling water flow rates to normal. The
procedure contained no warnings or cautions against cycling the valve. Once in the
field, the NLOs noted no signs or placards on the valve advising of any potential for
stem/disc separation. Because of the lack of any specific guidance to the contrary, the
operators concluded that it was acceptable to continue with the 1DG032 valve cycling
evolution.
In accordance with the approved LOS-DG-Q1 procedure steps, the NLOs cycled the
1DG032 valve. Cooling water flow decreased from approximately 475 gpm to 0 gpm,
and flow noises subsided. However, upon reopening the valve neither cooling water
flow indication nor increased flow noise were noted. After on-watch shift supervisors
were notified and a second attempt to cycle the valve was executed, operations
personnel concluded that the 1DG032 valve had probably suffered a stem/disc
separation.
The 1DG032 valve failure and interruption in cooling water flow resulted in the 1A RHR,
LPCS, and reactor core isolation cooling (RCIC) systems being rendered inoperable. A
subsequent licensee investigation identified that the 1DG032 valve is part of a group of
components with known tendencies for stem/disc separation. Some of these valves
have been replaced or repaired, some have failed and been abandoned (i.e., blank
flanged, etc.), and some, such as was the case with the 1DG032 valve, had not been
operated for years and their exact condition was not known. This information was
contained within the licensees computer database used to generate clearances/tagouts,
as well as on engineering prints specifically created to highlight the susceptible
components. Many members of the licensees staff, such as cycle planners, system
engineers, and work week managers, were aware of these susceptible components, but
the specific information was not provided to plant operators or properly captured in
procedures or other controlled reference documents.
13 Enclosure
Analysis
The inspector-identified performance deficiency with this issue was a failure on the part
of the licensee to accurately assess and properly manage the risk associated with the
cycling of the 1DG032 manual gate valve. Upon review of the event, the inspectors
determined that sufficient written information was available to the licensees organization
that should have alerted plant operators to the risk involved with cycling 1DG032. In
interviews with plant operators and other personnel, the inspectors identified that had
the susceptibility for 1DG032 stem/disc separation been better understood, on-watch
operations supervisors probably would not have allowed the evolution to have gone
forward, or, at a minimum, would have ensured that more controls and oversight were in
place during the evolution.
The objective of the Mitigating Systems Cornerstone of Reactor Safety is to ensure the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences (i.e., core damage). In accordance with NRC
Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports,
Appendix B, Issue Screening, the inspectors determined that the finding was of more
than minor significance in that it had a direct impact on this cornerstone objective.
Specifically, the licensees failure to properly assess and effectively manage the risk
associated with the 1DG032 valve cycling evolution resulted in the interruption of
supporting cooling water flow to Unit 1 Division 1 ECCS components, rendering these
components inoperable and unavailable.
The inspectors determined that the finding could be evaluated using the SDP in
accordance with IMC 0609, Significance Determination Process, and conducted a
Phase 1 characterization and initial screening. Because the finding only impacted a
single Division of ECCS and did not represent the loss of any entire systems safety
function, and because no Technical Specification allowed outage times were exceeded
and the finding was not related to external events such as fire, flooding, or adverse
weather, the inspectors determined it to be of very low safety significance (Green) and
within the licensees response band.
Enforcement
Section (a)(4) of 10 CFR 50.65 states that before performing maintenance activities
(including but not limited to surveillance, post-maintenance testing, and corrective and
preventive maintenance), the licensee shall assess and manage the increase in risk that
may result from the proposed maintenance activities. Contrary to this requirement, the
licensee failed to properly assess and effectively manage the increase in risk associated
with cycling the 1DG032 manual gate valve. Specifically, this type of valve was known
to be susceptible to stem/disc separation, posing the potential for increased risk when
cycling the valve.
The licensee had entered this issue into their corrective action program as IR 286665.
Corrective actions completed by the licensee include: hanging tags on susceptible
valves to warn personnel of the potential for stem/disc separation; validation of all
essential service water valves susceptible to stem/disc separation and providing a listing
of these components to plant operations; revision of applicable operating procedures to
14 Enclosure
include a precaution that identifies the valves that are susceptible to stem/disc
separation and a requirement to verify the applicability of valves prior to operation; and
review of the issue as a potential operator challenge/workaround. Because the licensee
has entered the issue into their corrective action program and the finding is of very low
safety significance, this violation of 10 CFR 50.65(a)(4) is being treated as an NCV,
consistent with Section VI.A of the NRC Enforcement Policy.
1R14 Operator Performance During Non-Routine Evolutions and Events (71111.14)
.1 Operator Response to 1C Circulating Water Pump Trip on January 4, 2005
a. Inspection Scope
The inspectors performed several hours of continuous control room observation to
evaluate operator performance in coping with an unexpected trip of the 1C circulating
water (CW) pump during a planned maintenance window for the 1A CW pump. The
inspectors reviewed operator logs and plant computer data to determine how the unit
responded and to verify that operator actions were appropriate, and consistent with
operator training and plant procedures. The licensees planned recovery actions,
procedures, reactivity manipulation briefings, and contingency plans were also reviewed
by the inspectors to identify any personnel performance issues. In addition, the
inspectors verified that any problems encountered during the non-routine evolution were
identified by the licensee, and appropriately entered into the corrective action program.
The observation of this non-routine evolution by the inspectors constituted a single
inspection sample.
b. Findings
No findings of significance were identified.
.2 Operator Response to the Losses of Unit 2 Shutdown Cooling on February 7, 2005
a. Inspection Scope
The inspectors performed several hours of control room observation to evaluate
operator performance in coping with two unplanned interruptions of shutdown cooling
flow. The first occurred at 7:56 a.m. due to valve isolations resulting from a trip of the
A reactor protection system (RPS) power supply. The second occurred at 10:55 a.m.
due to the failure of the reactor recirculation (RR) system B loop discharge stop valve,
F067B, to close after shutdown of the B RR pump. The inspectors reviewed operator
logs, vessel temperature traces, and plant computer data to determine unit conditions
and to verify that operator actions were appropriate, and consistent with operator
training and plant procedures. The licensees planned recovery actions, procedures,
reactivity manipulation briefings, and contingency plans were also reviewed by the
inspectors to identify any personnel performance issues. In addition, the inspectors
verified that any problems encountered during the non-routine evolution were identified
by the licensee, and appropriately entered into the corrective action program.
15 Enclosure
The observation of this non-routine evolution by the inspectors constituted a single
inspection sample.
b. Findings
No findings of significance were identified.
.3 Operator Response to the Identification of a Single Point Vulnerability Affecting
Division 1 and Division 2 4,160 Vac Safety Related Power
a. Inspection Scope
The inspectors evaluated operator performance during the identification of a single point
vulnerability affecting the 4,160 Vac safety related switchgear on both Division 1 and
Division 2 on both LaSalle units. The inspectors reviewed operator logs, clearance
orders, equipment status tags, and plant computer data to determine unit conditions and
to verify that operator actions were appropriate, and consistent with operator training
and plant procedures. The licensees planned recovery actions, procedures, reactivity
manipulation briefings, and contingency plans were also reviewed by the inspectors to
identify any personnel performance issues. In addition, the inspectors verified that any
problems encountered during the non-routine evolution were identified by the licensee,
and appropriately entered into the corrective action program.
The observation of this non-routine evolution by the inspectors constituted a single
inspection sample.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors reviewed the technical adequacy of the following operability evaluations
to determine the impact on Technical Specifications, the significance of the evaluations,
and to ensure that adequate justifications were documented:
- Degradation of Lisega snubber operating oil due to radiation exposure in the
Unit 1 and Unit 2 drywells (OE 04-008);
- Unit 1 core standby cooling system (CSCS) pump room ventilation system
following water intrusion into control panels;
- Evaluation to support the removal of standby liquid control (SBLC) containment
isolation valves (CIVs) from the 10 CFR 50, Appendix J, Type C local leak rate
testing (LLRT) program (EC 332208);
- Degraded cooling fans on Transformer 236Y (OE 04-007);
- L2R10 lost parts evaluations for the reactor vessel and connected primary
systems (EC 354196 and EC 354344).
16 Enclosure
Operability evaluations were selected based upon the relationship of the safety-related
system, structure, or component to risk.
These reviews constituted five inspection samples.
b. Findings
No findings of significance were identified.
1R16 Operator Workarounds (71111.16)
a. Inspection Scope
The inspectors reviewed an operator workaround involving the manual control of reactor
building ventilation control dampers. The inspectors reviewed the workarounds
potential to impact the operators ability to maintain reactor building differential pressure
below the Technical Specification limit and detect potential changes in secondary
containment integrity.
This review represented a single inspection sample.
b. Findings
No findings of significance were identified.
1R17 Permanent Plant Modifications (71111.17)
a. Inspection Scope
The inspectors reviewed the following modifications to verify that the design basis,
licensing basis, and performance capability of risk significant systems were not
degraded by the installation of the modifications. The inspectors also verified that the
modifications did not place the plant in an unsafe configuration.
- Unit 2 Division 2 residual heat removal service water (RHRSW) keep fill
elimination (EC 342975) and stainless steel valve replacements (EC 343542)
- Unit 2 steam dryer lifting lug upper support removal (EC 353949)
The inspectors considered the design adequacy of the modification by performing a
review, or partial review, of the modifications impact on plant electrical requirements,
material requirements and replacement components, response time, control signals,
equipment protection, operation, failure modes, and other related process requirements.
These reviews constituted three inspection samples.
b. Findings
No findings of significance were identified.
17 Enclosure
1R19 Post-Maintenance Testing (71111.19)
.1 Miscellaneous Post-Maintenance Testing Reviews
a. Inspection Scope
The inspectors selected the following post-maintenance activities for review. Activities
were selected based upon the structure, system, or component's ability to impact risk.
- Unit 1 drywell floor drain sump alternate fill up rate monitor post repair testing
and calibration
- Unit 1 rod position indication system testing following probe data receiver card
replacement
- Unit 2 A RPS motor generator set testing following voltage regulator repairs
The inspectors verified by witnessing the test or reviewing the test data that
post-maintenance testing activities were adequate for the above maintenance or repair
activities. The inspectors reviews included, but were not limited to, integration of testing
activities, applicability of acceptance criteria, test equipment calibration and control,
procedural use and compliance, control of temporary modifications or jumpers required
for test performance, documentation of test data, Technical Specification applicability,
system restoration, and evaluation of test data. Also, the inspectors verified that
maintenance and post-maintenance testing activities adequately ensured that the
equipment met the licensing basis, Technical Specifications, and Updated Final Safety
Analysis Report (UFSAR) design requirements.
These reviews constituted three inspection samples.
b. Findings
No findings of significance were identified.
.2 Unit 2 Division 1 125 V Battery Charger Return to Service Following Maintenance
a. Inspection Scope
The inspectors reviewed the post maintenance testing and the return to service of the
Unit 2 Division 1 125 Vdc battery charger, 2DC09E, following maintenance activities on
January 19, 2005 and January 28, 2005. Design changes to the 125 Vdc system were
reviewed as well as maintenance and operations procedures for the 125 Vdc system.
Inspectors evaluated licensee performance and knowledge level during operation of
these chargers.
The observation of this post-maintenance test by the inspectors constituted a single
inspection sample.
18 Enclosure
b. Findings
Introduction
A finding of very low safety significance was self-revealed when a design modification to
the Unit 2 Division 1 125 Vdc charger system was not appropriately incorporated into
operational procedures. This resulted in an under-voltage condition during an attempt to
swap on-service chargers. An NCV of 10 CFR 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings, for failure to properly incorporate design
changes into procedures for the 125 Vdc system, was identified.
Description
On January 19, 2005, during the return to service of the Unit 2 Division 1 125 Vdc
charger, 2DC09E, following maintenance, a Division 1 125 Vdc bus undervoltage alarm
was received. During the swap of the on-service charger, 2DC23E, with the oncoming
charger, 2DC09E, the oncoming charger failed to pick up load. This resulted in a low
voltage condition on the Division 1 125 Vdc bus and the subsequent inoperability of that
bus. 2DC23E was restored as the on-service charger and the bus undervoltage alarms
cleared. Total inoperability time for the Division 1 125 Vdc bus was approximately
23 minutes.
Troubleshooting was commenced to determine the cause of the failure. It was
subsequently determined that a procedural problem with LOP-DC-01, Battery Charger
Startup and Shutdown, was the cause of this failure. Changes to the battery charger
system since the last design modification had not been adequately incorporated into the
procedures used to swap battery chargers, or into operator training lesson plans.
Specifically, voltage metering on the 2DC09E battery charger tapped into the DC
circuitry in a different location than similar metering on the existing 2DC23E battery
charger. The differences in voltage metering taps between the two chargers resulted in
plant operators being presented with different indications when swapping from 2DC09E
to 2DC23E, as opposed to when swapping from 2DC23E to 2DC09E.
The procedure was revised and training for operators on the procedure revision was
conducted. The 2DC09E charger was also tested with a load bank to verify it was
operating properly.
On January 28, 2005, licensee personnel again attempted to swap 2DC09E with the
on-service charger, 2DC23E. During the swap, multiple control room alarms were
received because the oncoming charger bus voltage was too high. Though this did not
result in the inoperability of the DC bus, it did result in the inoperability of several
process radiation monitors (PRMs) and the Unit 2 off gas log pretreatment monitor. The
inspectors observed the evolution and discussed the issue with plant operations
personnel. The inspectors concluded that, although the licensee had revised the
procedure for swapping chargers and trained operators on the specific revision, plant
operators performing the actual charger swap were still unaware of the differences in
voltage metering between the two battery chargers.
19 Enclosure
Analysis
The performance deficiency associated with this event was a failure on the part of
licensee personnel to have incorporated relevant design information, specifically
information regarding differences in voltage metering between 2DC09E and 2DC23E,
into LOP-DC-01, Battery Charger Startup and Shutdown.
The objective of the Mitigating Systems Cornerstone of Reactor Safety is to ensure the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences (i.e., core damage). In accordance with NRC
Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports,
Appendix B, Issue Screening, the inspectors determined that the finding was of more
than minor significance in that it had a direct impact on this cornerstone objective.
Specifically, the inspectors concluded that the licensees performance deficiency was
primarily responsible for a low voltage condition on the Unit 2 Division 1 125 Vdc system
on January 19, 2005, which rendered this system inoperable for approximately
23 minutes.
The inspectors determined that the finding could be evaluated using the SDP in
accordance with IMC 0609, Significance Determination Process, and conducted a
Phase 1 characterization and initial screening. Because the finding involved the loss of
only one train of safety related equipment and the loss was for less than the Technical
Specification allowed outage time, the inspectors determined it to be of very low safety
significance (Green) and within the licensees response band.
Enforcement
Table 3.2-1 of the licensees Updated Final Safety Analysis Report (UFSAR) indicated
that the 125 Vdc battery chargers are subject to the requirements of 10 CFR 50,
Appendix B. Criterion V, Instructions, Procedures, and Drawings, of this appendix
states, in part, that: Activities affecting quality shall be prescribed by documented
instructions, procedures, or drawings, of a type appropriate to the circumstances and
shall be accomplished in accordance with these instructions, procedures, and drawings.
Contrary to this requirement, the licensee, by not incorporating relevant information
concerning battery charger voltage metering into the procedure for swapping battery
chargers, failed to properly prescribe an activity affecting quality, the swapping of battery
chargers, into the stations instructions and procedures for this task.
The licensee had entered this issue into their corrective action program as IR 287541.
Corrective actions planned and completed by the licensee include: revision of
LOP-DC-01 and training for operations personnel on new charger procedures. Because
the licensee has entered the issue into their corrective action program and the finding is
of very low safety significance, this violation of 10 CFR 50 Appendix B, Criterion V, is
being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy.
20 Enclosure
.3 Unit 1 Core Standby Cooling System (CSCS) Pump Room Ventilation System Control
Cabinet Water Intrusion
a. Inspection Scope
The inspectors reviewed repairs and testing of the Unit 1 Division 1 and Division 2
CSCS pump room ventilation system after water intrusion into the conduit system
resulted in erratic behavior of the Unit 1 Division 2 temperature controller. Repairs to
the controller and conduit system were inspected, including the method and
effectiveness of sealing the conduit to prevent further water intrusion.
The observation of this post-maintenance test by the inspectors constituted a single
inspection sample.
b. Findings
No findings of significance were identified. One unresolved item (URI) was identified.
On January 3, 2005, during a rain/snow shower, the control room received a high
temperature alarm for the Unit 1 Division 2 CSCS pump room ventilation system (VY).
The room temperature controller, 1TIC-VY024, was indicating 120 degrees. Actual
room temperature was verified to be 73 degrees. The erratic behavior of this
temperature controller resulted in the potential loss of temperature control for the
Division 2 CSCS pump room and, consequently, the inoperability of the C and D
RHRSW pumps and the B spent fuel pool cooling (FC) emergency makeup pump. In
January 2003, this same temperature controller had failed and had been replaced. The
cause of this failure was never established.
Subsequent to the adverse weather on January 3, 2005, the 1TIC-VY024 controller was
replaced with a new controller, but still continued to exhibit erratic behavior. The original
controller was reinstalled and it was noted during troubleshooting that water dripping into
the control panel from an internal conductor onto a terminal strip was causing stray
currents which resulted in the erratic behavior of this controller. Further investigation
revealed water intrusion inside the conduit connected to this control panel. Corrosion
and standing water were also located in junction box 1JB301A associated with this
conduit.
On January 5, 2005, repairs were performed to clean and dry the Division 2 VY conduit
system and clean, paint, and drill weep holes in junction box 1JB301A . An
extent-of-condition walkdown by the licensee noted that the Division 1 VY conduit and
control panel also exhibited signs of water intrusion. Long term rust deposits and water
dripping within the control panel were observed. This division was not considered
inoperable due to a wiring configuration difference between the Division 1 and Division 2
control panels that directed dripping water within the panel away from the terminal strip.
This wiring practice was commonly termed as installing drip loops and was required for
cable terminations of this type per licensee maintenance procedures.
On January 9, 2005, the licensee made repairs to the Division 1 VY conduits in an
attempt to stop the water intrusion by sealing the conduit. On February 15, 2005, during
21 Enclosure
a rain shower, inspectors in the plant identified water dripping from weep holes in the
Division 1 VY junction boxes from conduit that had supposedly been sealed several
days earlier to prevent such water intrusion.
On March 25, 2005, during a rain shower, inspectors again identified water dripping
from junction boxes on both Division 1 and Division 2 VY conduits that had previously
been repaired for similar water intrusion events.
At the time of the writing of this report, the inspectors had challenged licensee
engineering and maintenance personnel with several questions related to this issue. In
response, the licensee had entered multiple items associated with this event into their
corrective action program (IRs 287742, 287334, 287987, 287351, 287694, 288823,
308000, 301768, and 317267). Among the actions the licensee has performed, or plans
to perform, to address this issue include: a complete extent-of-condition review of all
through roof conduits that may be susceptible to water intrusion; drilling of weep holes in
all susceptible junction boxes; repairs to damage caused by water intrusion; the sealing
of the leaking conduit on Unit 1 Division 1 and Division 2 VY systems; and determining
the actual cause of the water intrusion into the conduits. This issue is considered
unresolved, pending the inspectors receipt and review of the licensees corrective action
program products and the steps taken per the licensees action plan to address the
nonconforming condition. (URI 05000373/2005002-05)
1R20 Outage Activities (71111.20)
a. Inspection Scope
The inspectors evaluated outage activities for an refueling outage that began on
February 7, 2005, and ended on March 16, 2005. The inspectors reviewed activities to
ensure that the licensee considered risk in developing, planning, and implementing the
outage schedule.
The inspectors observed or reviewed the reactor shutdown and cooldown, outage
equipment configuration and risk management, electrical lineups, selected clearances,
control and monitoring of decay heat removal, control of containment activities, startup
and heatup activities, and identification and resolution of problems associated with the
outage.
The inspectors review of outage activities represented a single inspection sample.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors selected the following surveillance test activities for review. Activities
were selected based upon risk significance and the potential risk impact from an
22 Enclosure
unidentified deficiency or performance degradation that a system, structure, or
component could impose on the unit if the condition were left unresolved. These
reviews constituted nine inspection samples.
- Unit 1 and Unit 2 drywell leak detection systems tests and calibrations
- Unit 1 and Unit 2 standby liquid control tank concentration tests
- Unit 2 standby liquid control pump operability/inservice test
- Unit 2 emergency core cooling systems divisional response time testing
- Unit 2 inboard and outboard feedwater check valve and outboard stop valve local
leak rate testing
- Unit 2 residual heat removal shutdown cooling return pressure isolation valve
leak rate test
- Unit 2 residual heat removal pressure isolation valve leak rate test
- Unit 2 standby liquid control explosive valve testing
The inspectors observed the performance of surveillance testing activities, including
reviews for preconditioning, integration of testing activities, applicability of acceptance
criteria, test equipment calibration and control, procedural use, control of temporary
modifications or jumpers required for test performance, documentation of test data,
Technical Specification applicability, impact of testing relative to performance indicator
reporting, and evaluation of test data.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a. Inspection Scope
The inspectors selected the following temporary modifications for review. The
inspectors reviewed the safety screening, design documents, UFSAR, and applicable
Technical Specifications to determine that the temporary modifications were consistent
with modification documents, drawings, and procedures. The inspectors also reviewed
the post-installation test results to confirm that tests were satisfactory and that the actual
impact of the temporary modification on the permanent system and interfacing systems
were adequately verified.
- Installation of alternate method for determining Unit 1 drywell floor drain sump
flow rate (TCCP 353167)
- Removal of 1DG032 internals and freeze seal (EC 353125)
- Energizing both 125 Vdc division 1 or 2 battery chargers simultaneously to
support battery charger testing (EC 340584)
These reviews constituted four inspection samples.
23 Enclosure
b. Findings
No findings of significance were identified.
1EP2 Alert and Notification System (ANS) Testing (71114.02)
a. Inspection Scope
The inspectors discussed with corporate and station-based Emergency Preparedness
(EP) staffs the operation, maintenance, and periodic testing of the ANS in the LaSalle
County Stations plume pathway Emergency Planning Zone (EPZ) to determine whether
the ANS equipment was adequately maintained and tested in accordance with
Emergency Plan commitments and procedures. The inspectors reviewed records of
2003 and 2004 preventive and non-scheduled maintenance activities, as well as
January 2004 through December 2004 ANS operability test results.
These activities constituted a single inspection sample.
b. Findings
No findings of significance were identified.
1EP3 Emergency Response Organization (ERO) Augmentation Testing (71114.03)
a. Inspection Scope
The inspectors reviewed and discussed with station EP staff the procedures that
included the primary and alternate methods of initiating an ERO activation to augment
the on-watch ERO and the provisions for maintaining the stations ERO call-out roster.
The inspectors reviewed critiques and a sample of corrective action program records of
unannounced off-hours augmentation drills, which were conducted monthly between
April 2004 and January 2005, to determine the adequacy of the critiques and associated
corrective actions. The inspectors also reviewed the EP training records of a random
sample of 30 LaSalle County Station ERO members, who were assigned to key and
support positions, to determine whether they were currently trained for their assigned
ERO positions. The inspectors also reviewed the LaSalle County Stations ERO roster
to verify that appropriate personnel were assigned to each response position.
These activities constituted a single inspection sample.
b. Findings
No findings of significance were identified.
24 Enclosure
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies (71114.05)
a. Inspection Scope
The inspectors reviewed a sample of Nuclear Oversight staffs 2004 reviews of the
LaSalle County Stations EP program to verify that these independent assessments met
the requirements of 10 CFR 50.54(t). The inspectors also reviewed critique reports and
samples of corrective action program records associated with those reviews. The
inspectors also reviewed the licensees critique of its emergency response to an actual
seismic event, which included an Unusual Event declaration, that occurred in
June 2004. The inspectors reviewed critique reports and samples of corrective action
program records associated with the 2004 biennial exercise, as well as various EP drills
conducted between July 2003 and December 2004, in order to verify that the licensee
fulfilled its drill commitments and to evaluate the licensees efforts to identify, track, and
resolve concerns identified during these activities. The inspectors also reviewed
samples of corrective action program documents associated with other aspects of the
Stations EP program.
These activities constituted a single inspection sample.
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1 Plant Walkdowns and Radiation Work Permit Reviews
a. Inspection Scope
The inspectors reviewed licensee controls and surveys in the following five radiologically
significant work areas within radiation areas, high radiation areas, and airborne
radioactivity areas in the plant and reviewed work packages which included associated
licensee controls and surveys of these areas to determine if radiological controls
including surveys, postings, and barricades were acceptable:
- Drywell control rod drive (CRD) pull/put activities;
- Reactor vessel disassembly and reassembly;
- Chemical decontamination and drywell work;
- Suppression pool diving;
- Low pressure heater bay maintenance.
This review represented one inspection sample.
25 Enclosure
The inspectors reviewed the radiation work permits (RWPs) and work packages used to
access these five areas and other high radiation work 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 noticeably malfunctioned or
alarmed.
This review represented one inspection sample.
The inspectors walked down and surveyed (using a calibrated NRC survey meter) these
five areas 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.
This review represented one inspection sample.
The inspectors reviewed RWPs for airborne radioactivity areas to verify barrier integrity
and engineering controls performance (e.g., high efficiency particulate air (HEPA)
ventilation system operation) and to determine if there was a potential for individual
worker internal exposures of greater than 50 millirem committed effective dose
equivalent. Work areas having a history of, or the potential for, airborne transuranics
were evaluated to verify that the licensee had considered the potential for transuranic
isotopes and provided appropriate worker protection. There were no airborne
radioactivity work areas identified during the course of the inspection.
This review represented one inspection sample.
The adequacy of the licensees internal dose assessment process for internal exposures
greater than 50 millirem committed effective dose equivalent was assessed. There
were no internal exposures greater than 50 millirem.
This review represented one inspection sample.
b. Findings
No findings of significance were identified.
.2 Problem Identification and Resolution
a. Inspection Scope
The inspectors reviewed the licensees self-assessments, audits, licensee event reports,
and special reports related to the access control program to verify that identified
problems were entered into the corrective action program for resolution.
This review represented one inspection sample.
26 Enclosure
The inspectors reviewed 15 corrective action reports related to access controls and 2
high radiation area radiological incidents when available (non-performance indicators
identified by the licensee in high radiation areas <1R/hr). Staff members were
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;
- Resolution of NCVs tracked in the corrective action system;
- Implementation/consideration of risk significant operational experience feedback.
This review represented one inspection sample.
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.
This review represented one inspection sample.
The inspectors reviewed licensee documentation packages for all performance indicator
(PI) events occurring since the PI events involved dose rates greater than 25 R/hr at
30 centimeters or greater than 500 R/hr at 1 meter. Barriers were evaluated for failure
and to determine if there were any barriers left to prevent personnel access. There
were no PI events occurring since the last inspection.
This review represented one inspection sample.
b. Findings
No findings of significance were identified.
.3 Job-In-Progress Reviews
a. Inspection Scope
The inspectors observed the following five jobs that were being performed in radiation
areas, airborne radioactivity areas, or high radiation areas for observation of work
activities that presented the greatest radiological risk to workers:
- Drywell CRD pull/put activities;
- Reactor vessel disassembly and reassembly;
27 Enclosure
- Chemical decontamination and drywell work;
- Suppression pool diving;
- Low pressure heater bay maintenance.
The inspectors reviewed radiological job requirements for these five activities, including
RWP requirements and work procedure requirements, and attended As-Low-As-Is-
Reasonably-Achievable (ALARA) job briefings.
This review represented one inspection sample.
The above review is combined with NRC IP 71121.02, ALARA, Planning, and Controls,
and documented in Section 2OS2.2.
Job performance was observed with respect to these requirements to verify that
radiological conditions in the work area were adequately communicated to workers
through pre-job briefings and postings. The inspectors also verified the adequacy of
radiological controls including required radiation, contamination, and airborne surveys
for system breaches; radiation protection job coverage which included audio and visual
surveillance for remote job coverage; and contamination controls.
This review represented one inspection sample.
Radiological work in high radiation work areas having significant dose rate gradients
was reviewed to evaluate the application of dosimetry to effectively monitor exposure to
personnel and to verify that licensee controls were adequate. These work areas
involved areas where the dose rate gradients were severe (diving activities and the
reactor water cleanup (RWCU) heat exchanger room) which increased the necessity of
providing multiple dosimeters and/or enhanced job controls.
This review represented one inspection sample.
b. Findings
No findings of significance were identified.
.4 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, of the RWP controls and limits in place, and that their performance had
accounted for the level of radiological hazards present.
This review represented one inspection sample.
The inspectors reviewed 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
28 Enclosure
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 the
Radiation Protection Manager.
This review represented one inspection sample.
b. Findings
(1) Electrician Enters the Drywell on the Wrong RWP
Introduction
A self-revealing finding of very low safety significance (Green) and an associated NCV
were identified when an electrician logged onto a general all-buildings minor
maintenance activities RWP and entered the drywell, a posted HRA, contrary to the
licensees Technical Specifications. The finding was identified when the electricians
electronic dosimeter alarmed after he entered a 106 millirem/hour dose field in the
drywell.
Description
On February 7, 2005, an electrician was assigned to minor electrical maintenance work
in the drywell.
The workers proceeded to the RP desk to sign on to the RWP 10003998, Unit 2
Drywell (construction) Minor Maintenance Activities for L2R10. This RWP contained
proper controls for the assigned activity in a HRA. The workers proceeded to the
electronic dosimeter (ED) station where the electrician mistakenly signed onto RWP
10003938, All-Building Minor Maintenance Activities. The ED computer sign-in had
displayed screens to allow the individual to verify the RWP number, and these screens
were incorrectly answered in the affirmative. The electrician knew the dose and dose
rate limits for the correct RWP from the HRA pre-job brief. The electrician entered the
radiologically controlled area (RCA) and proceeded to the work area at approximately
1:50 a.m. and left the RCA at 5:00 p.m.
When the electrician exited the drywell and checked out of the RCA, he received a
warning on the computer screen that he had received a dose rate alarm during the
entry. He immediately notified RP staff of the warning. The RP staff investigated the
event and identified that he had signed on to the wrong RWP.
The individual received a total dose of 4 millirem, and the maximum dose rate measured
by the ED was 106 millirem/hour.
The failure to assure through self-checking that each high radiation area entry is made
using the correct RWP that includes specification of radiation dose rates in the
immediate work area and other appropriate radiation protection equipment and
measures is contrary to Technical Specification 5.7.1: (a) requiring entry controls; and
(b) requiring that an appropriate RWP be utilized by workers.
29 Enclosure
The licensees initial prompt investigation determined the cause to be a failure of human
performance error prevention techniques. Specifically, the electrician lacked
self-checking and peer-checking in entering the wrong RWP and accepting the ED
log-in screens that asked if this was the correct RWP. As immediate corrective actions,
the individual was locked out of the stations RCA, and the licensee initiated an
investigation. Additionally, all site personnel were notified of this event through a station
safety alert.
Analysis
The inspectors determined that the performance deficiency associated with this event
was failure to follow procedure, in that the individual did not electronically sign onto the
right RWP. The finding, under the Occupational Radiation Safety Cornerstone, does not
involve the application of traditional enforcement because it did not result in actual
safety consequences or potential to impact the NRCs regulatory function and was not
the result of any willful actions. The finding was more than minor as it could be
reasonably viewed as a precursor to a more significant event. The finding is associated
with one of the cornerstone attributes, specifically occupational radiation safety.
The inspectors determined that the finding was more than minor because the
occurrence involved an individual worker potential unplanned, unintended dose resulting
from actions or conditions contrary to licensee procedures and radiation work permit
which could have been significantly greater as a result of a single minor, reasonable
alteration of the circumstances. The finding was evaluated using the Significance
Determination Process (SDP) for the Occupational Radiation Safety Cornerstone and
was determined to be of very low safety significance (Green). The finding did not
involve an ALARA issue, as collective dose was not an issue. Furthermore, the
individuals radiation exposure was low relative to regulatory limits; there was not a
substantial potential for a worker overexposure; and the licensees ability to assess
worker dose was not compromised.
Because the inspectors determined that the primary cause for the finding was related to
the cross-cutting aspect of human performance, it is discussed in Section 4OA4 as well.
Enforcement
Technical Specification 5.7.1(a) and 5.7.1(b) require for HRAs, with dose rates not
exceeding 1.0 rem per hour at 30 centimeters from the radiation source, that access to
and activities in each area shall be controlled by means of a RWP that includes the
specification of radiation dose rates in the immediate work area and other appropriate
radiation protection equipment and measures. Contrary to the above, on
February 7, 2005, an electrician received a dose rate alarm when working in the drywell
during the L2R10 refueling outage. The worker entered an elevated dose rate area
above the floor, an area that was not normally surveyed, and this action was contrary to
the limits of the RWP onto which he had electronically acknowledged. Because entry
into the RCA was conducted under an all-buildings scaffold activities RWP, the entry
into the HRA was monitored by EDs. Since the finding is of very low safety significance
and had been entered into the corrective action system as IR 218052, the associated
30 Enclosure
violation is being treated as an NCV, consistent with Section VI.A of the NRC
Enforcement Policy (NCV 05000374/2005002-06).
(2) Venture Pipefitters Enter HRA Without RWP Brief on February 13, 2005
No findings of significance were identified. One unresolved item (URI) was identified.
On February 13, 2005, a Radiation Protection Technician (RPT) identified that a
pipefitter foreman and two pipefitters had inappropriately gone past two HRA postings
and barricades to enter the condenser pit room. Prior to the unauthorized entry, the
pipefitters discussed their work and RWP limitations (RWP 1004122, Unit 2 Minor
Maintenance-Non-HRA) with RPTs at the low pressure heater bay access point. The
RPTs thought the pipefitters were working in the adjacent amertap room, which was not
a posted HRA. The RPTs and pipefitters confirmed through a 3-way communication
that the discussion was not an HRA brief and that they were not to enter any HRAs. In
addition, all three pipefitters had attended the required radworker training that
specifically challenged the workers on HRA entry requirements.
When the pipefitters entered the condenser pit room HRA to access their assigned work
area, they identified that they needed a survey completed before accessing a scaffold.
They requested assistance from a RPT in the area for this task. The RPT asked if they
had received an HRA brief. They told the RPT they had received the required brief.
The RPT completed the survey for them, and the pipefitters completed the assigned
work in the HRA and left the area. The highest dose rate for the pipefitters was
38 millirem/hour and the highest dose was 3.7 millirem. No electronic dosimeter alarms
were activated by the entry.
When the RPT returned to the low pressure heater bay access point he questioned why
he was not made aware that the pipefitters were being sent to the condenser pit for
assigned work. At this point, it was identified that the pipefitters were not properly
briefed and were on the wrong RWP.
Because the pipefitters had potentially been directed by their supervisor to enter the
HRA, the event remains under review by the NRC pending further investigation and is
categorized as an Unresolved Item. (URI 05000374/2005002-07)
.5 Radiation Protection Technician Proficiency
a. Inspection Scope
During job performance observations, the inspectors evaluated RPT 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.
This review represented one inspection sample.
31 Enclosure
The inspectors reviewed radiological problem reports which found that the 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 reported problems.
This review represented one inspection sample.
b. Findings
No findings of significance were identified.
2OS2 As Low As Is Reasonably Achievable Planning And Controls (ALARA) (71121.02)
.1 Radiological Work Planning
a. Inspection Scope
The inspectors evaluated the licensees list of work activities ranked by estimated
exposure that were in progress and reviewed the following five work activities of highest
exposure significance:
- Drywell CRD pull/put activities;
- Reactor vessel disassembly and reassembly;
- Chemical decontamination and drywell work;
- Suppression pool diving;
- Low pressure heater bay maintenance.
This review represented one inspection sample.
For these five activities, the inspectors reviewed the ALARA work activity evaluations,
exposure estimates, and exposure mitigation requirements in order to verify that the
licensee had established procedures, and engineering and work 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.
This review represented one inspection sample.
The inspectors compared the results achieved including dose rate reductions and
person-rem used with the intended dose established in the licensees ALARA planning
for these five work activities. Reasons for inconsistencies between intended and actual
work activity doses were reviewed.
This review represented one inspection sample.
b. Findings
No findings of significance were identified.
32 Enclosure
.2 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 radiation areas for observation of work
activities that presented the greatest radiological risk to workers:
- Drywell CRD pull/put activities;
- Reactor vessel disassembly and reassembly;
- Chemical decontamination and drywell work;
- Suppression pool diving;
- Low pressure heater bay maintenance.
The licensees use of ALARA controls for these work activities was evaluated.
Specifically, 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.
This review represented one inspection sample.
b. Findings
No findings of significance were identified.
.3 Source-Term Reduction and Control
a. Inspection Scope
The inspectors reviewed licensee records to determine the historical trends and current
status of tracked plant source terms and to evaluate if the licensee was making
allowances and had developed contingency plans for expected changes in the source
term due to changes in plant fuel performance issues or changes in plant primary
chemistry. Additionally, the inspectors reviewed the licensees chemical
decontamination activities and cold noble metals addition during this refueling outage.
This review represented one inspection sample.
b. Findings
No findings of significance were identified.
33 Enclosure
.4 Radiation Worker Performance
a. Inspection Scope
Radiation worker and RPT 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
work activity controls were being complied with. 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.
b. Findings
No findings of significance were identified.
.5 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).
This review represented one inspection sample.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
.1 Emergency Preparedness Performance Indicator Verification
a. Inspection Scope
The inspectors reviewed the licensees records associated with the three EP
performance indicators (PIs) listed below. The inspectors verified that the licensee
accurately reported these indicators in accordance with relevant procedures and
Nuclear Energy Institute guidance endorsed by NRC. Specifically, the inspectors
34 Enclosure
reviewed licensee records associated with PI data reported to the NRC for the period
January 2004 through December 2004. Reviewed records included: procedural
guidance on assessing opportunities for the three PIs; assessments of PI opportunities
during pre-designated control room simulator training sessions, the 2004 biennial
exercise, and mini-drills; revisions of the roster of personnel assigned to key ERO
positions; and results of periodic alert and notification system (ANS) operability tests.
The following PIs were reviewed:
Station Common
- ERO Drill Participation
- Drill and Exercise Performance
These reviews represented three inspection samples.
b. Findings
No findings of significance were identified.
.2 Data Submission Issue
a. Inspection Scope
The inspectors performed a review of the data submitted by the licensee for the 4th
Quarter 2004 performance indicators for any obvious inconsistencies prior to its public
release in accordance with IMC 0608, Performance Indicator Program.
This review did not represent an independent inspection sample.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
Cornerstones: Initiating Events and Mitigating Systems
.1 Routine Review of Identification and Resolution of Problems
a. Inspection Scope
As a part of the various inspection procedures used to accomplish Sections 1 and 2 of
this report, the inspectors verified that problems and issues associated with inspection
samples were entered into the licensees corrective action program (CAP). Additionally,
the inspectors verified that the licensee identified issues at an appropriate threshold and
that problems were properly addressed for resolution. CAP attributes reviewed
included: complete and accurate identification of the problem; that the timeliness of
problem review was commensurate with safety; that evaluation and disposition of
35 Enclosure
performance issues, generic implications, common causes, contributing factors, root
causes, extent of condition reviews, and previous occurrences reviews were proper and
adequate; and that classification and prioritization of corrective actions were
commensurate with safety and sufficient to prevent recurrence of the issue.
These routine reviews concerning the identification and resolution of problems were an
integral part of the inspection samples documented elsewhere in this report. As such,
they did not represent any additional inspection samples.
b. Findings
Introduction
A finding of very low safety significance (Green) was identified by the inspectors during
review of the circumstances associated with a small fire in the 2B RHR corner room on
February 16, 2005, (Section 1R05.2). The inspectors determined that the licensee had,
during several opportunities, failed to take timely and effective corrective actions with
respect to ignition control for hot work. An associated Non-Cited Violation (NCV) of
10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was also identified.
Description
On February 16, 2005, at approximately 2:30 p.m., work was in progress in the 2B RHR
corner room to demolish a section of pipe that was slated for removal as part of an
approved permanent plant modification. The work involved cutting a vertical run of
20-inch diameter pipe into sections approximately 1 foot in length to facilitate ease of
removal. A single fire watch was assigned to observe in progress hot work activities.
Fire blanketing was placed in the area of the hot work, with additional material
surrounding the floor piping penetration to prevent sparks from falling through the
penetration. A fire blanket extended outward for approximately 8 feet from the hot work
area. During the course of the hot work activities, some of the sparks generated by the
cutting were thrown past the area covered by the fire blanket. These sparks fell through
open floor grating to the 694' elevation below.
At some point following lunch, cleaning material was staged on the 694' elevation below
the area where the hot work was in progress. When interviewed as part of the licensees
ACE, the fire watch stated that he was not aware of the introduction of this combustible
material to this area. Sparks that fell from the hot work above ignited a small Class A
fire in this material. A laborer in the area detected the fire and attempted to extinguish it
by stepping on the flames. When this action was not successful, a mop was used in an
attempt to smother the flames. When this action, too, proved ineffective, the laborer
notified the fire watch on the level above, who was able to extinguish the fire with a dry
chemical fire extinguisher. The control room was notified by personnel involved in the
2B RHR corner room fire.
On February 15, 2005, the day before the fire, a region-based NRC inspector touring the
Unit 2 feedwater heater bay identified deficiencies relating to ignition control at no less
than four work locations where hot work was in progress. In each case, the inspector
observed sparks from in progress hot work activities thrown out beyond the established
36 Enclosure
fire blanket protection areas. The inspector estimated that the fire blanket coverage, at
each site he observed, extended out only 6 to 8 feet from the work location. This level of
coverage was well short of the 35 feet required by plant procedures governing hot work
ignition control. Consequently, each hot fire activity observed by the inspector had hot
sparks passing through deck grating and falling to the levels below where the actual work
was taking place. The inspector discussed his observations with the personnel
conducting the work and their assigned fire watches at each job site, however, because
the personnel did not seem to be responsive, in his opinion, to his comments, the
inspector also discussed the observations with a duty radiation protection (RP) technician
in the heater bay and the on-duty outage Heater Bay Coordinator.
Following the fire in the 2B RHR corner room on February 16, 2005, inspectors reviewed
the licensees actions in response to the NRC observations regarding hot work ignition
controls in the Unit 2 heater bay that had occurred on the preceding day. In discussions
with senior licensee managers, the inspectors identified that communication of the NRC
observations from the Unit 2 heater bay on February 15, 2005, had not gone beyond the
Heater Bay Coordinator, nor had the licensee generated an Issue Report (IR) to enter the
observations as required by their corrective action program (CAP).
On February 22, 2005, six days following the 2B RHR corner room fire, the NRC
Resident Inspector and a region-based inspector were conducting a routine plant tour
that included the 2B RHR corner room. The inspectors were surprised to find that their
passage through the lower levels of the 2B RHR corner room and up the stairs was
blocked by a shower of sparks from hot work in progress from above. When personnel
conducting the hot work noticed the NRC inspectors, they ceased grinding operations
and allowed the inspectors to climb the stairs and exit the 2B RHR corner room. This hot
work activity was for the same modification project that had caused the fire six days
earlier.
The inspectors immediately brought their observations to the attention of licensee
management personnel in the Outage Control Center. The licensee ordered work in the
2B RHR corner room stopped and conducted a follow-up inspection of the work location.
Licensee managers determined that some of the fire blanket material added to the
2B RHR corner room job site following the fire had been removed as a part of planned
housekeeping and demobilization efforts. However, three fire watches were present in
the 2B RHR corner room during the hot work and the potential for another fire was small.
The licensee generated IR 304516 to document their actions and the inspectors
observations.
Analysis
In reviewing the 2B RHR corner room fire, the inspectors evaluated the licensee
corrective actions for NRC observations concerning hot work ignition control passed to
licensee personnel both before and after the February 16, 2005 fire. Given the lack of
effective communication of this issue within the licensees organization, and the fact that
an IR had not been written for the issues discussed with the licensee on February 15, the
inspectors determined that there was a performance deficiency associated with the
corrective actions taken by the licensee. Specifically, the licencees response to
inspector observations regarding hot work ignition controls in the Unit 2 heater bay on
37 Enclosure
February 15, 2005, was narrowly focused and not properly documented or
communicated within the licensees organization, resulting in the potential for adverse
consequences to plant equipment and personnel in the vicinity of hot work. The
inspectors concluded that had the licensees corrective action response to the
February 15, 2005, observations been more thorough and robust, it is conceivable that
the 2B RHR corner room fire may not have occurred the following day. Similarly, the
inspectors observations in the 2B RHR corner room six days after the fire indicated that
the licensees corrective actions for the actual event were largely ineffective, as the same
deficient conditions in fire blanket coverage that had permitted the fire to occur in the first
place continued to exist.
The objective of the Initiating Events Cornerstone of Reactor Safety is to limit the
likelihood of those events that upset plant stability and challenge critical safety functions
during shutdown as well as power operations. In accordance with NRC Inspection
Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue
Screening, the inspectors determined that the finding was of more than minor
significance in that it had a direct impact on this cornerstone objective. Specifically, one
of the key attributes associated with this cornerstone objective is protection against fires,
and the inspectors determined that the licensees failure to take timely and effective
corrective actions with respect to hot work ignition control deficiencies constituted a clear
threat to fire prevention at the facility.
The inspectors determined that the finding could be evaluated using the SDP in
accordance with IMC 0609, Significance Determination Process, and conducted a
Phase 1 initial screening. Because the finding was associated with fire protection, this
was accomplished using IMC 0609, Appendix F, Attachment 1, Fire Protection SDP
Phase 1 Worksheet. As discussed in Section 1R05.2, the inspectors determined that
the finding was associated with the licensees ability to reach and maintain cold shutdown
conditions. As a result of the phase 1 screening, this finding was determined to be of very
low safety significance (Green) and within the licensees response band.
Enforcement
Criterion XVI of 10 CFR 50, Appendix B, states, in part, that: Measures shall be
established to assure that conditions adverse to quality, such as failures, malfunctions,
deficiencies, deviations, defective material and equipment, and nonconformances are
promptly identified and corrected. Contrary to this requirement, the licensee failed to
take adequate corrective actions for procedural noncompliances relating to hot work
ignition controls in the 2B RHR corner room. Specifically, on February 16, 2005, a fire
occurred in the 2B RHR corner room caused, in part, by procedural noncompliances
related to hot work ignition control. On February 22, 2005, the inspectors identified that
some of the same hot work ignition control procedural noncompliances were still present
in the 2B RHR corner room that could have adversely impacted plant equipment or
personnel.
Following various discussions with the inspectors on this issue, the licensee entered the
issue into their CAP as issue report (IR) 319064. This IR calls for a comprehensive
common cause analysis (CCA) by the licensee, which will examine the various fire
protection issues identified to determine whether or not a generic fire protection
38 Enclosure
programmatic weakness is present. Because the licensee has entered the issue into
their corrective action program and the finding is of very low safety significance (Green),
this violation of 10 CFR 50, Appendix B, Criterion XVI, is being treated as an NCV,
consistent with Section VI.A of the NRC Enforcement Policy.
.2 Selected Issue Follow-up Inspection: Corrective Actions for Emergency Diesel
Generator (EDG) Reverse Power Trips
Introduction
The inspectors selected the licensees actions in response to recurring reverse power
trips of the stations EDGs for a more in-depth review. Since 1989, the licensee has
recorded 25 reverse power trips of EDGs at the station. The focus of this inspection was
a review of the licensees root cause report (RCR) for a reverse power trip of the 2A EDG
that occurred on December 7, 2004, which was the most recent event.
The inspectors review of this issue constituted a single inspection sample.
a. Effectiveness of Problem Identification
(1) Inspection Scope
The inspectors reviewed RCR 280218, Reverse Power Trip of the 2A Diesel Generator,
to verify that the licensee's identification of the problems were complete, accurate, and
timely, and that the consideration of extent-of-condition review, generic implications,
common cause, and previous occurrences were adequate.
(2) Issues
As discussed in Section (b) that follows, the licensees ability to identify the underlying
cause for this ongoing issue has, in general, not been the reason that the issue has been
drawn out for such a long period of time. The licensees investigations following both the
June 2, 1999, reverse power trip of the 1B EDG and the February 9, 2000, reverse power
trip of the 2B EDG both readily identified problems associated with the procedural
requirement plant operators faced to drive EDG load down to less than 200 kW before
opening the EDG output breaker. The actions of evaluating the issue and ensuring that
the corrective actions taken were effective are where the licensees corrective action
processes fell short.
b. Prioritization and Evaluation of Issues
(1) Inspection Scope
In reviewing RCR 280218, Reverse Power Trip of the 2A Diesel Generator, the
inspectors considered the licensees evaluation and disposition of performance issues,
evaluation and disposition of operability issues, and application of risk insights for
prioritization of issues.
39 Enclosure
(2) Findings
Introduction
A finding of very low safety significance (Green) was identified by the inspectors. The
inspectors determined that the licensee had failed during prior opportunities to fully
evaluate the nature of the problem leading to various EDG reverse power trips. The
most recent of these events were a reverse power trip of the 2B EDG on
August 18, 2004, for which no root cause was ever determined, and a reverse power trip
of the 2A EDG that occurred on December 7, 2004, which was the topic of the licensees
root cause report (RCR). An associated Non-Cited Violation (NCV) of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Action, was also identified by the inspectors.
Description
On December 7, 2004, plant operators were performing a shutdown of the 2A EDG in
accordance with approved procedures. As part of this activity, the control room crew was
reducing 2A EDG load in preparation for opening the 2A EDG output breaker. Per the
procedure, load on the 2A EDG was reduced to approximately 200 kilowatts (kW) and
approximately 200 kilovolts-amperes-reactive (kVAR).
Just before the next step in the procedure, operators noted a caution statement that
identified the fact that the EDG can become unstable and trip on reverse power if allowed
to go below 200 kVAR for more than 1.5 seconds. The control room crew was aware of
this caution and discussed the next actions for reducing load below 200 kW/200 kVAR
and then opening the EDG output breaker. While performing this next step, the control
room crew received a 2A EDG Trouble Alarm. Operators in the field reported local
alarms for EDG undervoltage, reverse power, and an EDG lockout.
As a part of the RCR, the licensee conducted interviews with the operators that shutdown
the 2A EDG. These interviews revealed that the plant operators took approximately
3 seconds to complete the opening of the EDG output breaker actions, versus the
procedurally stated caution that called for less than 1.5 seconds. The license concluded
that the requirement for the operators to act in a mere 1.5 seconds constituted a human
performance challenge.
Since 1989, there have been 25 recorded reverse power trips of EDGs at LaSalle
Station. Among the more notable events reviewed by the inspectors were:
- On June 2, 1999, the 1B EDG tripped on reverse power. An apparent cause
evaluation (ACE) was performed for this event and identified that at low load (less
than 200 kW), the EDG is in an inherently unstable position relative to the grid.
However, there were no corrective actions associated with this investigation. The
ACE was closed based on a statement by personnel that proper guidance existed
in the EDG operating procedure and that no additional action was required.
- On February 9, 2000, the 2B EDG tripped on reverse power. An investigation
identified the root cause as an operator skill-based human performance error in
the untimely opening of the output breaker. The operators actions to reduce
40 Enclosure
load, then perform a self-check, then request a peer-check, all prior to opening
the EDG output breaker were determined to require too much time. The reverse
power trip occurred as a result. However, based on the evaluations of the
licensees engineering staff, the 200 kW/200 kVAR caution limits in the EDG
procedures were considered appropriate and no procedural revisions took place.
- On August 18, 2004, the 2B EDG tripped on reverse power. The licensees
investigation focused almost primarily on the equipment failures subsequent to
the reverse power trip. The investigation plan did, however, call for a review of
the previous root cause for 2B EDG trip in 2000, and an assessment of the
adequacy of the corrective actions. In addition, a review of procedural and
human performance aspects of the EDG shutdown process were also required.
Despite this, however, there was no root cause identified associated with the
reverse power trip on August 18, and no corrective actions to specifically prevent
recurrence were instituted.
Analysis
In reviewing the EDG reverse power trips at the station leading up to the most recent
reverse power trip of the 2A EDG on December 7, 2004, the inspectors determined that
there was a performance deficiency associated with the corrective actions taken by the
licensee. Specifically, in response to the prior events, one as recently as
August 18, 2004, the licensees evaluation of the issue failed to generate any corrective
actions to address the inherently unstable position into which plant operators were being
placed by the procedural requirement to drive EDG load down below 200 kW before
opening the EDG output breaker. In one case as discussed above, in 1999, the
licensees evaluation actually did determine the cause of the reverse power trips to be
due to this procedural requirement and the naturally unstable position created by it.
However, no corrective actions were taken. While following the August 18, 2004,
reverse power trip of the 2B EDG actions were created to evaluate potentially changing
the EDG operating procedures to provide less limitations on tripping the output breaker,
these evaluations were not given a high enough priority for them to have been
completed by the time the December 7, 2004, reverse power trip occurred.
Subsequently, only after the 2A EDG reverse power trip on December 7, 2004, were the
evaluations completed in rapid order and procedure changes enacted.
The objective of the Mitigating Systems Cornerstone of Reactor Safety is to ensure the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences (i.e., core damage). In accordance with NRC
Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix
B, Issue Screening, the inspectors determined that the finding was of more than minor
significance in that it had a direct impact on this cornerstone objective. Specifically, the
inspectors concluded that the licensees performance deficiency was responsible for the
reverse power trip of the 2A EDG on December 7, 2004, which caused the EDG to be
unavailable for an additional 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br />.
The inspectors determined that the finding could be evaluated using the SDP in
accordance with IMC 0609, Significance Determination Process, and conducted a
Phase 1 characterization and initial screening. Because the finding involved the loss of
41 Enclosure
only one train of safety related equipment and the loss was for less than the Technical
Specification allowed outage time, the inspectors determined it to be of very low safety
significance (Green) and within the licensees response band.
Enforcement
Criterion XVI of 10 CFR 50, Appendix B, states, in part, that: Measures shall be
established to assure that conditions adverse to quality, such as failures, malfunctions,
deficiencies, deviations, defective material and equipment, and nonconformances are
promptly identified and corrected. Contrary to this requirement, the licensee failed to
promptly identify and correct procedural deficiencies associated with the unloading and
securing of the stations EDGs. These procedural deficiencies contributed to or directly
caused 25 EDG reverse power trips since 1989. Following a subsequent reverse power
trip of the 2A EDG on December 7, 2004, the licensee entered the issue into their CAP
as IR 280218. This issue report led to a RCR, with the following corrective actions
planned or completed: establishment of a less restrictive EDG load limit to allow
opening the EDG output breaker when load is less than approximately 500 kW;
additional training for licensed operators in the areas of EDG theory and operation and
the effects of reverse power conditions on diesel generators; and revision of simulator
modeling for EDGs to more accurately reflect actual plant performance for reverse
power trips. Because the licensee has entered the issue into their corrective action
program and the finding is of very low safety significance, this violation of 10 CFR 50,
Appendix B, Criterion XVI, is being treated as an NCV, consistent with Section VI.A of
the NRC Enforcement Policy. (NCV 05000374/2005002-09)
c. Effectiveness of Corrective Actions
(1) Inspection Scope
The inspectors reviewed multiple related CAP documents relating to the 25 EDG
reverse power trips on record since 1989 at the station. The intent of this review was to
determine if the CAP actions addressed generic implications, and to verify that
corrective actions were appropriately focused to correct the problem.
(2) Issues
The inspectors determined that the licensees corrective actions for EDG reverse power
events, that actually produced corrective actions, had only marginal impact in reducing
the number and frequency of the EDG reverse power trip occurrences. However, as
discussed in the section above, there were EDG reverse power trip events that did not
generate any corrective actions. For the actions taken in the aftermath of the reverse
power trip of the 2B EDG on August 18, 2004, the inspectors concluded that the
licensees planned actions had a good probability for success, but were not prioritized
for completion in time to prevent the subsequent December 7, 2004, reverse power trip
of the 2A EDG. These corrective actions included a Corporate Engineering review of
the reverse power trip settings for all LaSalle EDGs to determine if there was additional
margin in the setpoints, and a review to determine if the unloading sequence could be
changed to permit opening the EDG output breaker at higher loads.
42 Enclosure
4OA3 Event Follow-up (71153)
Cornerstones: Initiating Events and Mitigating Systems
.1 Single Failure Vulnerability of Safety Related 4,160 Vac Division 1 and Division 2
Protective Relay Circuitry (ENS 41366)
a. Inspection Scope
On January 27, 2005, Crystal River Unit 3 (CR-3) discovered a single failure that could
prevent both EDGs and both offsite power sources from supplying power to their
respective engineered safeguards (ES) buses. This was a condition reportable under
10 CFR 50.72 (b)(3)(ii)(B), for a plant being in an unanalyzed condition that significantly
degraded plant safety (ENS 41362).
Just prior to lunch on February 1, 2005, the LaSalle Station Electrical System
Engineering Supervisor was informed of the CR-3 event and provided a copy of
ENS 41362 by the LaSalle Station NRC Senior Resident Inspector. LaSalle Station
engineers reviewed the safety related bus protective relaying circuitry to determine if a
similar vulnerability existed. In the late afternoon of the following day, plant engineers
determined that a single failure vulnerability existed for LaSalle between the current
transformer (CT) circuits of the divisional safety related buses (e.g., 141Y to 142Y,
241Y to 242Y).
Upon notification of the discovery and subsequent entry into a 12-hour Technical
Specification Required Action potentially leading to the shutdown of both LaSalle units,
inspectors responded to the plant to monitor the licensees actions. The inspectors
observed plant parameters and status; evaluated the performance of plant systems and
licensee actions; and confirmed that the licensee properly reported the event as
required by 10 CFR 50.72. The inspectors determined that all systems responded as
intended, and that no human performance errors complicated the event response.
The inspectors response to and review of this event constituted a single inspection
sample.
b. Findings
No findings of significance were identified. One URI was identified.
At approximately 3:42 p.m. on February 2, 2005, plant operators entered a 12-hour
Technical Specification Required Action for unavailability of offsite and onsite power
systems. A licensee analysis of the issue determined that the CT circuits that supply the
overcurrent relay scheme for each divisional bus were connected to a common point
that supplies control room indication for the total station auxiliary transformer (SAT) Y
winding power (kW) and current (amperes). Further, licensee engineers determined
that an open circuit condition on any of the CT phases downstream of the common point
in the circuit would have resulted in an unbalanced current condition, which would have
initiated a trip of the associated SAT feed breakers for the applicable buses (e.g., 141Y
and 142Y, 241Y and 242Y). Specifically, the current unbalance would have actuated
43 Enclosure
the ground fault relays, causing the SAT feed breaker relays to lock out both divisions.
Following a trip of the bus feed breakers, the lockout relay for the respective bus would
have initiated a trip of the other bus breakers and prevented any closure of these
breakers. The ultimate result would have been a loss of all onsite and offsite power
sources to both 4160 Vac Division 1 and Division 2 safety related buses, because no
EDG or offsite power source would have been permitted to close onto the respective
Division 1 or Division 2 safety buses.
A temporary modification was developed and installed on each unit to isolate the
common metering circuitry between the Division 1 and Division 2 buses responsible for
the single point vulnerability. These modifications were installed and Technical
Specification Required Actions exited on Unit 1 in 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, 23 minutes, and on Unit 2 in
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, 48 minutes. All actions were monitored by the inspectors. The licensee
entered the issue into their corrective action program as IR 297076, and into their
corporate corrective action program as IR 299641.
The issue is presently considered unresolved pending a more detailed NRC review of
the licensees root cause report and LER for this issue. (URI 05000373/2005002-10;
.2 Inadvertent Reactor Recirculation Flow Increase Results in Unit 1 Reactor Power
Excursion to 103.17 Percent
a. Inspection Scope
On February 23, 2005, the inspectors responded to the control room following
notification from the licensee that the Unit 1 licensed reactor power limit of
3489 megawatts thermal (MWth) had been exceeded by approximately 3.17 percent for
several minutes following an unplanned and unexpected increase in reactor recirculation
flow. The inspectors observed plant parameters and status; evaluated the performance
of plant systems and licensee actions; and confirmed that the licensee properly reported
the event as required by Section 2.F(a) of Facility Operating License No. NPF-11. The
inspectors further determined that no nuclear fuel thermal limits were violated, and that
the event was bounded by the events discussed in the UFSAR.
The inspectors response to and review of this event constituted a single inspection
sample.
b. Findings
No findings of significance were identified. One URI was identified.
On February 23, 2005, at approximately 11:41 a.m., Unit 1 exceeded License
Condition 2.C (1), which limits the maximum thermal power of the unit to 3489 MWth.
Unit 1 reached a peak transient power of approximately 3599.5 MWth, or
103.17 percent of the licensed limit, for about 8 minutes.
At approximately 11:46 a.m., the Unit 1 control room supervisor (CRS), a licensed senior
reactor operator (SRO) observed that Unit 1 power had increased from 1194 megawatts
44 Enclosure
electric (MWe) to 1223 MWe, and directed the on-watch nuclear station operator (NSO),
a licensed reactor operator (RO) to lower power to 95 percent. From approximately
11:47 a.m. to 11:48 a.m., the NSO attempted to reduce reactor power using the
LOWER pushbutton on the reactor recirculation (RR) ganged (i.e., master) flow control
station. After two attempts to lower power using the RR ganged flow control station, the
NSO did not believe that power was responding as it should have, and he placed the RR
flow controllers for each RR loops flow control valve (FCV) into manual and closed them
both to approximately 80 percent at 11:49 a.m. The FCVs responded, and reactor
power was reduced to about 3471 MWth, or approximately 99.5 percent. Plant power
was subsequently stabilized at about 95 percent while the licensee began an
investigation of the event.
At approximately 5:34 p.m., the licensee contacted the NRC Region III Director of
Reactor Projects via telephone, in accordance with the reporting conditions of
Section 2.F(a) of the Unit 1 license, to discuss the event. A follow on written report was
sent on March 9, 2005.
At the time of this writing, the event is still under investigation by the licensee. FCVs on
both LaSalle units (4 valves total) were being maintained in manual control pending the
outcome of the investigation. Initial troubleshooting of the RR ganged flow controller
had not revealed any abnormalities; however, further diagnostic testing at an off site lab
was planned. The licensees investigation into potential equipment problems associated
with the RR flow controllers was entered into their CAP as IR 304613. This investigation
was scheduled for completion in April 2005.
While the event did not trigger any control board annunciator alarms (none should have
been triggered based on a review of the event by the inspectors), the licensee
investigated the on-watch crews apparent lack of response to several low-level plant
process computer alarms that were actuated on increasing plant pressure and power.
This root cause investigation was being conducted within the licensees CAP under
IR 305612, and was expected to be completed in April 2005.
In addition to maintaining FCVs in manual control, corrective actions taken by the
licensee at this point also included changing several plant process computer alarms
from low-level alarms, which annunciate only briefly and then are automatically silenced,
to higher level alarms that require operator action to silence the alarm tones. Computer
alarms included in this change were MWth, MWe, and reactor pressure.
This issue is considered unresolved pending the inspectors receipt and review of the
licensees CAP investigations regarding any potential equipment malfunctions of the RR
flow control system, and the root cause investigation into the event
45 Enclosure
4OA4 Cross-Cutting Aspects of Findings
Cornerstones: Initiating Events, Barrier Integrity and Occupational Radiation
Safety
Human Performance
Several of the findings and one of the licensee-identified violations described elsewhere
in this report had human performance deficiencies as their major causal elements.
- A Green finding and associated NCV described in Section 1R05.2 involved the
failure of plant personnel conducting hot work to follow procedural requirements
for fire blanket protection in the vicinity of the work site. The improper fire
blanket coverage and lack of attentiveness on the part of the assigned fire watch
and other licensee personnel responsible for ensuring that ignition controls in the
vicinity of hot work were being properly applied resulted in a small Class A fire
in the 2B RHR corner room.
- A Green finding and associated NCV described in Section 1R13.2 involved the
failure of maintenance planners and maintenance first line supervisors to have
properly identified the risk associated with an electrical meter replacement for
the 1A circulating water (CW) pump. The improper assessment of risk, in
combination with an inadvertent electrical short caused during the meter
replacement itself, resulted in a trip of the 1C CW pump, which was in service at
the time of the 1A CW pump maintenance window.
- A finding and an associated NCV described in Section 2OS1.4(1) involved the
failure of personnel to follow established plant procedures and radiological
practices with respect to HRAs. An individual signed in on a general area RWP,
and subsequently entered a HRA to conduct a work in the Unit 2 drywell,
contrary to plant Technical Specifications.
- A licensee-identified violation discussed in Section 4OA7 involved the failure of
maintenance contractor personnel to adequately follow written work instructions
regarding the removal of a U-bolt/pipe hanger for the Unit 2 reactor recirculation
(RR) system in the Unit 2 drywell. The wrong U-bolt was removed, contrary to
written job instructions in an approved work package; the error was subsequently
discovered by the licensee and corrected several days later. While the missing
U-bolt was determined to have been of no consequence for the established plant
conditions, if left uncorrected it would have been consequential for RR pipe
qualification during operation.
These human performance deficiencies were procedure compliance and adherence
related.
46 Enclosure
4OA5 Other
Cornerstone: Mitigating Systems
.1 (Discussed) Unresolved Item 05000373/2004005-04; 05000374/2004005-04: Standby
Liquid Control (SBLC) Boron Tank Volume/Concentration Measurements
One URI from a prior inspection report was discussed. This did not represent any
inspection samples.
On November 19, 2004, the Unit 2 main control room received a SBLC tank level alarm.
Plant operators concluded that the bubbler system that provides both tank level and
alarm indications was plugged and required cleaning. After the bubbler was cleaned,
however, the SBLC tank low level alarm still was actuated. A manual measurement
conducted by operations personnel using a T-square indicated a tank volume of
4717 gallons. Since the low level alarm setpoint was at 4700 gallons, the licensee
decided to add water to the SBLC tank to increase the volume of solution.
On November 23, 2004, operations and chemistry personnel added water to the Unit 2
SBLC tank and, as required by procedure, sampled the sodium pentaborate (boron
solution) concentration afterwards. Volume was measured using the T-square at
4767 gallons and boron solution concentration was determined to be 12.99 percent.
The minimum required Technical Specification boron solution concentration for this
volume is 12.97 percent, per Technical Specification Figure 3.1.7-1. Chemistry
technicians noted that there was little margin to the Technical Specification limit, and
plans were made to perform a sodium pentaborate addition to the tank during the
following week.
Just prior to midnight on November 25, 2004, Unit 2 operators were performing their
daily Technical Specification surveillance to verify SBLC tank level within the limits of
Technical Specification Figure 3.1.7-1. Measured tank volume was 4750 gallons. This
volume was below the required Figure 3.1.7-1 limit for the current boron solution
concentration of 12.99 percent. For a volume of 4750 gallons, Figure 3.1.7-1 specified
a minimum boron solution concentration of 13.02 percent. SBLC tank volume was
subsequently measured using the T-square, and 4762 gallons was the result. This
volume was exactly at the Technical Specification Figure 3.1.7-1 limit for a boron
solution concentration of 12.99 percent. However, questions by the on-watch operations
crew raised doubt as to the accuracy of the T-square volume measurement when it was
realized that an unauthorized operator aid in the form of a placard on the side of the
SBLC tank was being used to convert inches measured with the T-square to tank
volume in gallons. The conversion method on the placard was different than the
calculation used by chemistry technicians specified in their approved plant procedures.
Using the approved calculation from a chemistry procedure, operators recalculated the
SBLC tank volume from their T-square measurement and determined it to be 4757
gallons, which was once again below the Figure 3.1.7-1 limit. Both trains of SBLC were
declared inoperable and the applicable Technical Specification 8-hour shutdown time
clock entered. Chemistry technicians were called in to sample the SBLC boron solution
tank concentration, and obtained a measured value of 13.11 percent. When compared
47 Enclosure
with the T-square volume of 4757 gallons, this concentration value was within the limits
of Technical Specification Figure 3.1.7-1 and both trains of SBLC were declared
The licensee conducted an extent-of-condition review and determined that both Unit 1
and Unit 2 SBLC tanks had routinely been maintained with little margin to the
Figure 3.1.7-1 limits for volume and boron solution concentration. The licensee has
entered multiple issues associated with this event into their corrective action program
(CRs 276755, 277113, 277439, 281247, and 281238). These condition reports have
generated several corrective action program investigations, including a root cause report
(RCR 276755) and an apparent cause evaluation (ACE 277113).
As of the publication of this inspection report, the inspectors continue to review the
licensees CAP and associated engineering documents for this issue. Initial reviews by
the inspectors have yielded several questions regarding the licensees methods for
calculating SBLC tank volume. Over the course of the inspection period, the licensees
engineering staff have developed several similar methods for calculating SBLC tank
volume, each in an attempt to demonstrate that no past violations of Technical
Specification requirements had occurred with respect to measured sodium pentaborate
concentration and volume. The issue remains unresolved pending completion of the
inspectors reviews of the licensees calculations. (URI 05000373/2004005-04;
4OA6 Meetings
.1 Exit Meeting
The inspectors presented the inspection results to the Site Vice President,
Ms. S. Landahl, and other members of licensee management on April 5, 2005. The
inspectors discussed the controls associated with a single proprietary engineering
evaluation from General Electric Company that was reviewed by the inspectors. No
other proprietary information was identified.
.2 Interim Exit Meetings
Interim exits were conducted for:
- A refuel outage baseline radiation protection inspection with the Site Vice
President, Ms. S. Landahl, and other members of the licensees staff on
February 18, 2005.
- A refuel outage baseline engineering inspection of ISI with the Site Vice
President, Ms. S. Landahl, and other members of the licensees staff on
March 1, 2005.
- A baseline emergency preparedness inspection with the Site Vice President,
Ms. S. Landahl, and other members of the licensees staff on March 25, 2005.
48 Enclosure
4OA7 Licensee-Identified Violations
Cornerstones: Barrier Integrity and Emergency Preparedness
The following violations of very low significance were identified by the licensee and are
violations of NRC requirements which meet the criteria of Section VI of the NRC
Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.
- Criterion V of 10 CFR 50, Appendix B, Procedures, Instructions, and Drawings,
requires that activities affecting quality be prescribed by documented
instructions, procedures, or drawings, of a type appropriate to the circumstances,
and that activities be accomplished in accordance with these instructions,
procedures, or drawings. Contrary to these requirements, on February 16, 2005,
contractor maintenance personnel removed a U-bolt from a reactor recirculation
(RR) system pipe support in the Unit 2 drywell that was not the U-bolt specified
in their approved work instructions. The error was discovered on
February 19, 2005, by the licensee and corrected.
Inspectors determined that the issue was of more than minor significance
because if left uncorrected it would have become a more significant safety
concern. Specifically, while the missing U-bolt was determined to have been of
no consequence for the established plant conditions, if left uncorrected it would
have been consequential for RR piping qualification during operation. Because
there were no actual consequences associated with the issue, the inspectors
determined it to be of very low significance and within the licensees response
band. The licensee had entered the issue into their CAP as IR 303383.
- Part 50.47 of 10 CFR, paragraph (b)(15), requires, in part, that radiological
emergency response training be provided to those who may be called on to
assist in an emergency. Table B-1 of the licensees standardized emergency
plan required that the minimum on-shift staffing included two radiation protection
(RP) personnel for in-plant protective actions. In September 2004, EP staff
based at another of the licensees Illinois nuclear stations identified that this
emergency plan commitment was met during weekends and holidays by one
on-shift RP technician and one on-shift chemistry technician. However, the
licensee also determined that chemistry technicians training had evolved such
that the training no longer met all requirements to provide in-plant protection
actions.
In early December 2004, the licensee completed an adequate root cause
investigation of this concerns impact at each of its Illinois nuclear stations.
Timely corrective actions included assigning two RP technicians on all back
shifts, initiating revision of the standardized ERO training procedure, and
initiating an assessment of ERO position qualifications in cases where some
ERO training was being performed by other departments. Because no actual
emergency events had occurred that required in-plant protective actions and the
49 Enclosure
licensees timely corrective actions included staffing a minimum of two RP
technicians on-shift, this violation is not more than of very low significance, and is
being dispositioned as an NCV.
ATTACHMENT: SUPPLEMENTAL INFORMATION
50 Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
S. Landahl, Site Vice President
D. Enright, Plant Manager
J. Bearden, Emergency Planning Coordinator
T. Connor, Maintenance Director
L. Coyle, Operations Director
D. Czufin, Site Engineering Director
C. Dieckmann, Training Manager
A. Ferko, Nuclear Oversight Manager
F. Gogliotti, System Engineering Manager
P. Holland, Regulatory Assurance - NRC Coordinator
B. Kapellas, Radiation Protection Manager
A. Kochis, ISI Coordinator
H. Madronero, Engineering Programs Manager
C. Minor, NDE Level III
W. Riffer, Emergency Planning Manager
T. Simpkin, Regulatory Assurance Manager
C. Wilson, Station Security Manager
Nuclear Regulatory Commission
B. Burgess, Chief, Reactor Projects Branch 2
1 Attachment
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000374/2005002-01 NCV Failure to Properly Implement Procedure Requirements for
Hot Work and Ignition Control Results in a Fire in the 2B
RHR Corner Room (Sections 1R05.2 and 4OA4)05000373/2005002-02 NCV Failure to Assess and Manage Risk Associated with the 1A
Circulating Water Pump Electrical Meter Replacement
Results in the Trip of the 1C Circulating Water Pump
(Sections 1R13.2 and 4OA4)05000373/2005002-03 NCV Failure to Assess and Manage Risk Associated with the
Cycling of the 1DG032 Manual Gate Valve Results in
Inoperable and Unavailable ECCS Components
(Section 1R13.3)05000374/2005002-04 NCV Failure to Incorporate Relevant Design Information into
Battery Charger Operating Procedure Results in DC Bus
Undervoltage Condition (Section 1R19.2)05000373/2005002-05 URI Unit 1 CSCS Pump Room Ventilation System Control
Cabinet Water Intrusion (Section 1R19.3)05000374/2005002-06 NCV Electrician Enters HRA (Drywell) When Signed On To
General Area RWP (Sections 2OS1.4(1) and 4OA4)05000374/2005002-07 URI Contractor Pipefitters Enter Condenser Pit HRA Without
Required RP Briefing (Section 2OS1.4(2))05000374/2005002-08 NCV Failure to Take Timely and Effective Corrective Action for
Hot Work Ignition Control Issues (Section 4OA2.1)05000374/2005002-09 NCV Failure to Take Timely and Effective Corrective Action for
Emergency Diesel Generator (EDG) Reverse Power Trips
Results in Additional EDG Inoperability and Unavailability
(Section 4OA2.2)05000373/2005002-10 URI Single Failure Vulnerability of Safety Related 4160 Vac
05000374/2005002-10 Division 1 and Division 2 Protective Relay Circuitry
(ENS 41366) (Section 4OA3.1)05000373/2005002-11 URI Unit 1 Reactor Power Excursion to 103.18 Percent
(Section 4OA3.2)
2 Attachment
Closed
05000374/2005002-01 NCV Failure to Properly Implement Procedure Requirements for
Hot Work and Ignition Control Results in a Fire in the 2B
RHR Corner Room (Sections 1R05.2 and 4OA4)05000373/2005002-02 NCV Failure to Assess and Manage Risk Associated with the 1A
Circulating Water Pump Electrical Meter Replacement
Results in the Trip of the 1C Circulating Water Pump
(Sections 1R13.2 and 4OA4)05000373/2005002-03 NCV Failure to Assess and Manage Risk Associated with the
Cycling of the 1DG032 Manual Gate Valve Results in
Inoperable and Unavailable ECCS Components
(Section 1R13.3)05000374/2005002-04 NCV Failure to Incorporate Relevant Design Information into
Battery Charger Operating Procedure Results in DC Bus
Undervoltage Condition (Section 1R19.2)05000374/2005002-06 NCV Electrician Enters HRA (Drywell) When Signed On To
General Area RWP (Sections 2OS1.4(1) and 4OA4)05000374/2005002-08 NCV Failure to Take Timely and Effective Corrective Action for
Hot Work Ignition Control Issues (Section 4OA2.1)05000374/2005002-09 NCV Failure to Take Timely and Effective Corrective Action for
Emergency Diesel Generator (EDG) Reverse Power Trips
Results in Additional EDG Inoperability and Unavailability
(Section 4OA2.2)
Discussed
05000373/2004005-04 URI SBLC Tank Level and Boron Solution Concentration
05000374/2004005-04 Measurement Issues (Section 4OA5)
3 Attachment
LIST OF DOCUMENTS REVIEWED
1R01 Adverse Weather Protection
Procedures:
- LOA-TORN-001; High Winds/ Tornado; Revision 4
- OP-AA-108-111; Adverse Condition Monitoring and Contingency Planing; Revision 1
- OP-AA-108-111-1001; Severe Weather Guidelines; Revision 1
1R04 Equipment Alignment
Issue Reports:
- 141023; Apparent Failure of Div. II CSCS Room Temperature Controller; 1/24/2003
- 154515; Div 3 CSCS Pump Room Fans Did Not Secure Following EDG Run;
4/17/2003
- 236085; Errors in Analysis Affecting Max Anticipated CSCS Rm Temp; 7/14/2004
- 266846; Love Controller Replacement; 10/25/2004
- 283233; 1TIC-VY017 Reads Low; 12/16/2004
- 287334; Temperature Controller is Erratic, Not Giving True Readings; 1/3/2005
- 287351; Conduit Has a Leak Up at the Roofline - Causing 1TIC-VY024; 1/04/2005
- 287694; Ref. Issue Report #287351 WO # 769178-01; 1/4/2005
- 287742; Water in Local Control Panel 1PL73J; 1/5/2005
- 287987; FIN Follow-Up from Troubleshooting 1TIC-VY024 Erratic Ind; 1/5/2005
- 301768; Water Identified in Junction Boxes Feeding 1PL73J; 2/15/2005
- 302014; (NRC Identified) Discrepancy Between OPS Lesson Plan and UFSAR;
2/16/2005
- 307568; 2E12-F353C Div 2 CSCS RHR Root Valve Leaks By Excessively; 3/2/2005
- 308000; Install Drain Hole in J-Box for Damper Motor 0TZ-VD00; 3/3/2005
Operability Evaluation:
- OE 96155; Clarification of 1(2)VY05C Operability to Support DG Operations;
11/23/1996
Procedures:
- LOP-FC-02E; Unit 2 Fuel Pool Cooling Electrical Checklist; Revision 3
- LOP-FC-02M; Unit 2 Fuel Pool Cooling Mechanical Checklist; Revision 6
- LOP-DG-06E; Unit 1 A DG Cooling System Electrical Checklist; Revision 5
- LOP-DG-06M; Unit 1 A Diesel Generator Cooling System Mechanical Checklist;
Revision 12
- LOP-DG-07E; Unit 1 B Diesel Generator Cooling System Electrical Checklist;
Revision 5
- LOP-DG-07M; Unit 1 B Diesel Generator Cooling System Mechanical Checklist;
Revision 11
- LOP-DG-08E; Unit 0 Diesel Generator Cooling System Electrical Checklist; Revision 8
- LOP-DG-08M; Unit 0 Diesel Generator Cooling System Mechanical Checklist;
Revision 18
- LOP-DG-09E; Unit 2 A Diesel Generator Cooling System Electrical Checklist;
Revision 4
4 Attachment
- LOP-DG-09M; Unit 2 A Diesel Generator Cooling System Mechanical Checklist;
Revision 7
- LOP-DG-10E; Unit 2 B Diesel Generator Cooling System Electrical Checklist;
Revision 4
- LOP-DG-10M; Unit 2 B Diesel Generator Cooling System Mechanical Checklist;
Revision 9
- LOP-RH-04E; Unit 2 Residual Heat Removal System Electrical Checklist; Revision 14
- LOP-RH-2BM; Unit 2 B Residual Heat Removal System Mechanical Checklist;
Revision 0
- LOP-RH-2CM; Unit 2 C Residual Heat Removal System Mechanical Checklist;
Revision 0
- LOP-RHWS-1AM; Unit 1 A RHR Service Water System Mechanical Checklist;
Revision 1
- LOP-RHWS-1BM; Unit 1 B RHR Service Water System Mechanical Checklist;
Revision 3
- LOP-RHWS-2AM; Unit 2 A RHR Service Water System Mechanical Checklist;
Revision 1
- LOP-RHWS-2BM; Unit 2 B RHR Service Water System Mechanical Checklist;
Revision 2
- LOP-VD-01E; Unit 1 A Diesel Ventilation System Electrical Checklist; Revision 7
- LOP-VD-02E; Unit 2 A Diesel Ventilation Electrical Checklist; Revision 6
- LOP-VD-03E; Unit 1 Diesel Vent (VD) Electrical Checklist; Revision 5
- LOP-VD-04E; Unit 2 B Diesel Generator Ventilation Electrical Checklist; Revision 5
- MA-MW-726-022; Electrical Cable Termination and Inspection; Revision 0
Work Orders:
- 536202; Apparent Failure of Controller 1TIC-VY024; 1/24/2003
- 769178; Apparent Failure of Controller 1TIC-VY024; 1/04/2005
- 770108; Water in Local Control Panel 1PL73J; 1/12/2005
- 743426; Install/Remove Temp. Level Indication for LLP-2004-007; 3/6/2005
Updated Final Safety Analysis Report; Revision 15:
- Chapter 9, Auxiliary Systems
- Chapter 6, Section 6.3.2.2.4 - LPCI subsystem
1R05 Fire Protection
Procedures:
- CC-AA-201; Plant Barrier Control Program; Revision 5
- OP-MW-201-004; Fire Prevention for Hot Work; Revision 0
- OP-MW-201-007; Fire Protection System Impairment Control; Revision 3
- OP-AA-201-001; Fire Marshal Tours; Revision 2
- OP-AA-201-008; Pre-Fire Plans; Revision 1
- OP-AA-201-009; Control of Transient Combustible Material; Revision 4
- LS-AA-128; Regulatory Review of Proposed Changes to the Approved Fire Protection
Program; Revision 0
- LOS-FP-D1; Fire Protection Door Daily Surveillance; Revision 2
5 Attachment
Issue Reports:
- 302209; Small Fire in Unit 2 Reactor Building - 694 Elevation; 2/16/2005
- 302447; Near Miss - Fire Extinguisher Malfunction; 2/16/2005
- 304516; (NRC Identified) RHR Keep Fill Modification Fire Protection Awareness;
2/23/2005
Control Room Time Clock Tracking Sheet for Fire Watch Active Patrols; 2/9/2005 -
2/11/2005
Fire Protection Impairment Permits:
- 2-04-189-TRM
- 2-04-146-TRM
- 2-02-056-TRM
Plant Barrier Impairment Permits:
- DR-500.00r5
- 2B DG Access Hatch.00r5
- DR-503.00r5
Fire Watch Inspection Logs; 2/9/2005 - 2/11/2005
Pre-Fire Plans for Fire Zones 4F1, 4E1, and 4E3
La Salle County Nuclear Station Fire Protection Report Vol. 1:
- H.3.4.12 : Unit 1 Auxiliary Equipment Room - Fire Zone 4E1
- H.3.4.14 : Unit 1 Division 2 Essential Switchgear Room - Fire Zone 4E3
- H.3.4.16 : Unit 1 Division 1 Essential Switchgear Room - Fire Zone 4F1
Technical Requirements Manual :
- Vol. 4, Section 3.3p; Fire Detection Instrumentation
Updated Final Safety Analysis Report:
- Fig. 9.5-1 Fire Protection System; Sheets 17 and 22
1R08 Inservice Inspection Activities
Issue Reports:
- 303540; (NRC-Identified) Extent of Condition Review for IR 142187; 2/20/2005
- 142187; Pipe Support FW02-2875C Found Damaged; 1/31/2003
- 195554; Rejectable Indication on VT-3 Examination of FW02-1158X; 1/15/2004
- 195712; Snubber NB13-1001-S Failed on High Drag; 1/15/2004
- 195988; UT Indications in LP and HP Piping Inside the Reactor; 1/17/2004
- 196074; Additional UT Indications in LPCS Piping Inside the Reactor; 1/18/2004
- 212765; Error in LPCS Flaw Sizing Calculation; 4/1/2004
EC 341014; Evaluation of Bent FW Pipe Clamp M09-FW02-2875C; Revision 0
6 Attachment
Operating Experience:
- NRC IN 2004-08: Reactor Coolant Pressure Boundary Leakage Attributable to
Propagation of Cracking in Reactor Vessel Nozzle Welds
- G.E. RICSIL 082: Core Spray Nozzle to Safe End Weld Leak; AIR No.
373-458-97-00082.00
- Magnetic Particle Examination Data Sheet Report No. 2R10-109; Component
RH40-2877X; 2/28/2005
- UT Examination Summary Sheet No: 2R09-010, WO No: 430431; Weld
ID: LCS-2-BH; 2/3/2003
- UT Examination Summary Sheet No: 2R09-015, WO No: 430431; Weld
ID: LCS-2-N4D; 1/30/2003
- UT Examination Summary Report No. 2R10-010; Component ID: LCS-2-N2B,
Recirculation Inlet Nozzle; 2/28/2005
Work Order:
- 96094687; Replace 2E12-F325B/326B Double Block Valves with Two Single Valves;
9/24/2002
Prints and Drawings:
- ISI-RH-2009; Inservice Inspection Isometric, Residual Heat Removal System, Unit 2;
Revision B
- M09-RH40-2877X, Sheet 1; Pipe Support, Residual Heat Removal System, Unit 2;
Revision F
Procedures:
- GE-UT-705; Procedure for the Examination of Reactor Pressure Nozzle Inner Radius
and Nozzle to Vessel Welds with the GERIS 2000 OD in Accordance with Appendix VIII;
Version No. 4
- MT-EXLN-102V0; Procedure for Magnetic Particle Examination Using AC Yoke, Dry
Powder, or Wet Visible; Revision 2
1R11 Licensed Operator Requalification Program
Licensed Operator Requalification Scenario Guide:
- ESG 64; Revision 0
TQ-AA-106; Licensed Operator Requal Training Program; Revision 6
1R12 Maintenance Effectiveness
Sodium Pentaborate Sample Results for Unit 1 and Unit 2 SBLC Storage Tanks;
June 2004 - December 2004
Engineering Changes:
- 338147; SBLC Tank Level; Revision 0
- 352973; SBLC Tank Level Tee Square; Revision 0
7 Attachment
- 353491; Engineering Determination of Volume Via Gallons per Inch of Height in the
Units 1&2 SBLC Storage Tank (EPN) 1(2) C41-A001; Revisions 0 & 1
Procedures:
- CC-AA-103-2001; Set point Change Control; Revision 2
- CY-AA-130-200; Quality Control; Revision 6
- LCP-110-9; Determination of High Range Boron (Sodium Pentaborate); Revision 22
- LCP-310-09; Standby Liquid Control Tank Sampling; Revision 8
- LOP-SC-05; Changing Sodium Pentaborate Concentration in Standby Liquid Control
(SBLC) Solution Tank; Revision 18
Information Notice 86-48; Inadequate Testing of Boron Solution Concentration in the
Standby Liquid Control System; 6/13/1986
Issue Reports:
- 083484; SLC System Operability During Air Tank Sparging; 11/20/2001
- 276560; No Procedure Guidance for Sodium Pentaborate Addition Calculation;
11/24/2004
- 276755; SBLC Concentration Limits Outside TA limits; 11/25/2004
- 276839; NRC Identified Point of Discovery for SBLC Inop; 11/26/2004
- 277113; Unauthorized Operator Aid Found on Standby Liquid Control (SBLC) Solution
Tank; 11/26/2004
- 277439; NRC Identified Issue with Use of T Square for SBLC Tank Level; 11/29/2004
- 281238; Standby Liquid Control Solution Tank Volume Determination; 12/10/2004
- 281244; UFSAR Sections Not Up to Date for Standby Liquid Control to Include
Low-Level Alarm and Technical Specification 3.1.7 (Standby Liquid Control Figures);
12/10/2004
- 281247; Chemistry Procedures Not Up to Date for Technical Specification 3.1.7
(Standby Liquid Control Figures); 12/10/2004
- 283765; Sodium Pentaborate Concentration Outside Optimum Range; 12/17/2004
- 296489; SBLC Volume Resample Not Routed for Ops Review; 2/1/2005
1R13 Maintenance Risk Assessments and Emergent Work Control
Engineering Change:
- EC 353657; Isolation of Metering to Common 141Y/142Y and 241Y/242Y Safety
Related Buses; Revision 0
Issue Reports:
- 141023; Apparent Failure of Div. II CSCS Room Temperature Controller; 1/24/2003
- 154515; Div 3 CSCS Pump Room Fans Did Not Secure Following EDG Run;
4/17/2003
- 236085; Errors in Analysis Affecting Max Anticipated CSCS Rm Temp; 7/14/2004
- 266846; Love Controller Replacement; 10/25/2004
- 283104; HPCS DG Room Pressurized During DG Start; 12/16/2004
- 283233; 1TIC-VY017 Reads Low; 12/16/2004
- 286665; Stem to Disc Separation on 1DG032; 12/30/2004
- 287334; Temperature Controller is Erratic, Not Giving True Readings; 1/3/2005
- 287351; Conduit Has a Leak Up at the Roofline - Causing 1TIC-VY024; 1/4/2005
8 Attachment
- 287541; 1C Circ Water Pump Tripped; 1/4/2005
- 287694; Ref. Issue Report #287351 WO # 769178-01; 1/4/2005
- 287742; Water in Local Control Panel 1PL73J; 1/5/2005
- 287987; FIN Follow-Up from Troubleshooting 1TIC-VY024 Erratic Ind; 1/5/2005
- 290618; CSCS Valve PMs Critical Prior to L1R11 Need Deferral; 1/13/2005
- 293279; U-1 DWFD FUR 1UR-RF002 Pen 1 Ind > 1 GPM Above Alternate; 1/22/2005
- 297076; Vulnerability of Division 1 & 2 Protective Relay Circuitry; 2/4/2005
- 299188; Lack of Minimum 6-inch Physical Separation in Division 1 & 2 CTs; 2/8/2005
- 303991; DWFD Sump Flow Indication Pegged Upscale; 2/22/2005
- 304111; Possible Failed Instrument (Level Switch) 1C11-N013B; 2/22/2005
- 304853; Troubleshooting Results for Unit 1 SDV 1/2 Scram; 2/24/2005
Procedures:
- LOA-CW-101; Unit 1 Circulating Water System Abnormal; Revision 11
- LOR-1PM03-J-B406; Circulating Water Pump 1CW01P A/B/C Auto Trip; Revision 3
- LOP-CW-03; Startup and Operation of the Circulating Water System; Revision 26
- LOP-CW-09; Circulating Water System Ice Melting; Revision 13
- LOR-1PM13J-A301; Drywell Floor Drain Sump Level Hi, Hi Hi, or Pump Start Failure;
Revision 4
- LIS-PC-121; Unit 1 Drywell Floor Drain Sump Discharge Flow Calibration; Revision 1
- LOS-AA-S101; Unit 1 Shiftly Surveillence; Revision 28
- LOS-DG-Q1; 0 Diesel Generator Auxiliaries Inservice Test; Revision 38
- LSCS P.G. No. 130; Equipment to Be Worked Around the Clock; Revision 0
Corporate RCR 299641; Single Failure Vulnerability of Safety Related Division 1 & 2
Protective Relay Circuitry Root Cause Analysis; 3/8/2005
Operability Evaluation:
- OE 05-001; Minimum 6-inch Physical Separation in Division 1 & 2 CTs; Revision 0
Work Order:
- 545611-01; IM Contingency for DWFD Loop Instruments; 2/22/2005
1R14 Operator Performance During Non-Routine Plant Evolutions and Events
Issue Reports:
- 297076; Vulnerability of Division 1 & 2 Protective Relay Circuitry; 2/4/2005
- 298353; 2B-33 F067B Steam Coming From Packing Around Stem; 2/7/2005
- 298462; 2B RR PP Discharge Valve Would Not Stroke Closed; 2/7/2005
- 299188; Lack of Minimum 6-inch Physical Separation in Division 1 & 2 CTs; 2/8/2005
- 300143; 2B33-F067B Failed to Close; 2/9/2005
- 305823; SDC Not in Operation; 2/26/2005
Corporate RCR 299641; Single Failure Vulnerability of Safety Related Division 1 & 2
Protective Relay Circuitry Root Cause Analysis; 3/8/2005
9 Attachment
Engineering Change:
- EC 353657; Isolation of Metering to Common 141Y/142Y and 241Y/242Y Safety
Related Buses; Revision 0
Unit 2 Operator Logs; 2/7/2005
Operability Evaluation:
- OE 05-001; Minimum 6-inch Physical Separation in Division 1 & 2 CTs; Revision 0
Procedures:
- LOA-CW-101; Unit 1 Circulating Water System Abnormal; Revision 11
- LOP-CW-03; Startup and Operation of the Circulating Water System; Revision 26
- LOP-CW-09; Circulating Water System Ice Melting; Revision 13
- LOP-RR-09; Reactor Recirc Pump Shutdown; Revision 21
- LOR-1PM03-J-B406; Circulating Water Pump 1CW01P A/B/C Auto Trip; Revision 3
1R15 Operability Evaluations
Issue Reports:
- 288363; Results of Lisega Snubber Test Results; 1/6/2005
- 287334; Temperature Controller is Erratic, Not Giving True Readings; 1/3/2005
- 287742; Water in Local Control Panel 1PL73J; 1/5/2005
- 287987; FIN Follow-Up from Troubleshooting 1TIC-VY024 Erratic Ind; 1/5/2005
- 301768; Water Identified in Junction Boxes Feeding 1PL73J; 2/15/2005
Engineering Evaluation:
- Report No. R93-007S; Engineering Evaluation of NRC IE Notice 89-63 for LaSalle
County, Dresden, and Quad Cities Stations All Units; Revision 0
NRC Information Notice:
- 89-63; Possible Submergence of Electrical Circuits Located Above the Flood Level
Because of Water Intrusion and Lack of Drainage; 9/5/1989
Operability Evaluations:
- OE 04-008; Lisega Snubbers; Revision 3
- OE 04-007; Degraded Fans on Transformer 236Y; Revision 1
Engineering Changes:
- 332208; Evaluation of Appendix J Testing Requirements on the Standby Liquid Control
System; Revision 0
- 354196; L2R10 Lost Parts Evaluation for Items That Could Reach the Reactor Vessel;
Revision 0
- 354344; L2R10 Refuel Outage Nuclear Fuels Lost Parts Evaluation; Revision 0
1R16 Operator Workarounds
Issue Reports:
- 311171; Multiple TS 3.6.4.1 Entries Due to U2 VR System Operation; 3/10/2005
- 311529; Unexpected Change in Reactor Building Differential Pressure; 3/11/2005
10 Attachment
- 311672; Unit 1 VR Exh Flow Oscillates with Constant Signal to Damper; 3/11/2005
- 311795; L2R10 LL : VR System and RB DP Oscillations; 3/12/2005
- 312176; Sudden Increase (More Negative) in RB DP; 3/13/2005
Engineering Change:
- 352527; MR90 Review to Maintain VR DP During Troubleshooting of VR;
Revisions 0 & 1
Procedures:
- CC-AA-102; Design Input and Configuration Change Impact Screening; Revision 9
- LOP-VR-01; Reactor Building Ventiallation System Startup and Operation; Revision 31
- LS-AA-104; Exelon 50.59 Review Process; Revision 4
Work Order:
- 731302-11; Replace/ Calibrate U-2 VR Supply Instruments; 3/7/2005
1R17 Permanent Plant Modifications
Calculations:
- GEN 01-002; Generic Lead Shielding Blanket & Support Detail Qualification;
Revision 0
- L-002804; Installation of Permanent Lead Shielding Blankets Inside Unit 2 Drywell;
Revision 1
Engineering Changes:
- 342975; Unit 2 Residual Heat Removal Service Water Keep Fill Elimination; Revision 4
- 343542; Replace Carbon Steel CSCS Valves with Stainless Steel Valves ; Revision 2
- 332685; Install Permanent Lead Shielding in Unit 2 Drywell; Revision 1
- 353949; Alternate Detail for the Steam Dryer Lifting Lug Upper Support; Revision 0
Procedure:
- CC-AA-102; Design Input & Configuration Change Impact Screening; Revision 9
1R19 Post-Maintenance Testing
Issue Reports:
- 292281; Div 1 125 VDC Transient During Charger Swap; 1/19/2005
- 293279; U-1 DWFD FUR 1UR-RF002 Pen 1 Ind > 1 GPM Above Alternate; 1/22/2005
- 293389; LOP-DC-01 Revision; 1/23/2005
- 295228; Hi Voltage During U2 Division 1 Charger Swap; 1/28/2005
- 297795; Difference in 125VDC Divisional Charger Metering; 2/4/2005
- 298477; A RPS Half Scram During LOS-RP-W1 - IN Disc Rupture; 7/7/2005
- 298631; IN Rupture Disk Blew on Loss of A RPS; 2/7/2005
- 317267; NRC Identifies Water Dripping from Weep Hole in VY JB; 3/25/2005
Engineering Changes:
- 340584; Evaluate Acceptability of Energizing Both 125 VDC Division 1 or 2 Battery
Chargers Simultaneously to Support Battery Charger Testing; Revision 0
- 346528; Provide Guidance for the Use of Intermittent Loads; Revision 0
11 Attachment
Engineering Change Request:
- 368281; Battery Charger Troubleshooting as an Intermittent Load; 1/21/2005
Procedures:
- CC-AA-308; Control and Tracking of Electrical Load Changes; Revision 4
- LES-DC-103A; Division I Battery Charger Capacity Test; Revision 11
- LIS-PC-121; Unit 1 Drywell Floor Drain Sump Discharge Flow Calibration; Revision 1
- LOP-DC-01; Battery Charger Startup and Shutdown; Revisions 25 & 26
- LOR-1PM13J-A301; Drywell Floor Drain Sump Level Hi, Hi Hi, or Pump Start Failure;
Revision 4
- LOS-AA-S101; Unit 1 Shiftly Surveillence; Revision 28
Work Orders:
- 545611-01; IM Contingency for DWFD Loop Instruments; 2/22/2005
- 734945-02; Potentially Degraded RPIS Circuit Cards due to Diodes; 1/26/2005
- 774091-02; EM Replace 2A RPS Voltage Regulator; 2/15/2005
1R20 Outage Activities
Issue Reports:
- 298740; SRM D Detector Stuck Withdrawn; 2/8/2005
- 298741; IRM D Stuck Inserted; 2/8/2005
- 298322; Received B Half Scram Due to H IRM Hi=Hi; 2/7/2005
- 299196; Operator Injury During U-2 Div 3 CSCS Work; 2/8/2005
- 300701; Wrong Unit Error; 2/12/2005
- 307158; Lead Pump on the Div 2 CSCS Sump Found in the Stop Pos; 3/2/2005
- 307578; 2E12-F050A Fails High Pressure Water Leak Test; 3/2/2005
- 307589; L2R10 LL: 2B21-F032A Repair After Unacceptable LLRT Result; 3/2/2005
- 311369; Crud Burst Resulted in Increased Dose Rates on Refuel Floor; 3/11/2005
- 314018; Low Bearing Oil Pressure, Suspect Leak/ Hole in Pipe; 3/17/2005
Procedures:
- LGP-2-1; Normal Unit Shutdown; Revision 65
- LGP-1-1; Normal Unit Startup; Revision 73
- LGP1-S1; Master Startup Checklist; Revision 55
- LOA-RR-201; Unit 2 Recirculation Pump System Abnormal; Revision 13
- LIS-RR-205A; Unit 2 Recirculation Pump Trip System A Breaker Arc Suppression
Response Time Testing; Revision 7
- LES-RP-101; RPS MG Set Startup and Operation; Revision 9
- LOP-DW-02; Drywell Entry and Inspection (Shutdown, Startup or Operation);
Revision 13
- LOP-DW-01; Drywell Close Out (After Outage); Revision 38
- OP-AA-108-108-1001; Drywell/Containment Closeout; Revision 0
- LOS-DG-209; Unit 2 Integrated Division I Response Time Surveillance; Revision 1A
- LOS-DG-210; Unit 2 Integrated Division II Response Time Surveillance; Revision 1
- LOS-DG-211; Unit 2 Integrated Division III Response Time Surveillance; Revision 0
12 Attachment
L2R10 Shutdown Safety Management Program
10 CFR 50.59 Screenings and Evaluations:
- L05-73; LaSalle Unit 2 Cycle 11 Reload Package; Revision 0
- L05-74; LaSalle Unit 1 and 2 GE-14 Fuel Implementation; Revision 0
1R22 Surveillance Testing
Engineering Changes:
- 338147; SBLC Tank Level; Revision 0
- 352973; SBLC Tank Level Tee Square; Revision 0
- 353491; Engineering Determination of Volume Via Gallons per Inch of Height in the
Units 1&2 SBLC Storage Tank (EPN) 1(2) C41-A001; Revisions 0 & 1
Engineering Change Request:
- 352281; Provide Information in Eng Change or Equivalent on Delta Between V-Notch
and the Totalizer; 10/09/2001
Information Notice 86-48; Inadequate Testing of Boron Solution Concentration in the
Standby Liquid Control System; 6/13/1986
Issue Reports:
- 083484; SLC System Operability During Air Tank Sparging; 11/20/2001
- 276560; No Procedure Guidance for Sodium Pentaborate Addition Calculation;
11/24/2004
- 276755; SBLC Concentration Limits Outside TA limits; 11/25/2004
- 276839; NRC Identified Point of Discovery for SBLC Inop; 11/26/2004
- 277113; Unauthorized Operator Aid Found on Standby Liquid Control (SBLC) Solution
Tank; 11/26/2004
- 277439; NRC Identified Issue with Use of T Square for SBLC Tank Level; 11/29/2004
- 281238; Standby Liquid Control Solution Tank Volume Determination; 12/10/2004
- 281244; UFSAR Sections Not Up to Date for Standby Liquid Control to Include
Low-Level Alarm and Technical Specification 3.1.7 (Standby Liquid Control Figures);
12/10/2004
- 281247; Chemistry Procedures Not Up to Date for Technical Specification 3.1.7
(Standby Liquid Control Figures); 12/10/2004
- 283765; Sodium Pentaborate Concentration Outside Optimum Range; 12/17/2004
- 287208; DWFDS Fillup Rate High; 1/03/2005
- 290678; Noble Gas Channel Alarm Will Not Clear; 1/14/2005
- 291499; DWFDS Fillup Rate Reading 1.1 GPM; 1/18/2005
- 293279; U-1 DWFD FUR 1UR-RF002 Pen 1 Ind > 1 GPM Above Alternate;1/22/2005
- 296489; SBLC Volume Resample Not Routed for Ops Review; 2/1/2005
- 298625; MSL Drain Valves 2B21-F019/F016 Failed LLRT in LTS 100-4; 2/7/2005
- 301672; Feedwater Check Valve 2B21-F032A Failed As-Found LLRT; 2/14/2005
- 304012; Anomolies Noted During LES-SC-201 Surveillance; 2/22/2005
- 304021; Problems Encountered During the Performance of LES-SC-201; 2/22/2005
- 307210; SBLC Circuit Continuity Loss Fuse Found Blown; 3/2/2005
- 307242; Opposite Division Fuse Blown Following LOS-SC-R1; 3/2/2005
- 309172; L2R10 LL: SBLC Issues During L2R10; 3/6/2005
13 Attachment
Procedures:
- CC-AA-103-2001; Set point Change Control; Revision 2
- CY-AA-130-200; Quality Control; Revision 6
- LCP-110-9; Determination of High Range Boron (Sodium Pentaborate); Revision 22
- LCP-310-09; Standby Liquid Control Tank Sampling; Revision 8
- LOP-SC-05; Changing Sodium Pentaborate Concentration in Standby Liquid Control
(SBLC) Solution Tank; Revision 18
- LOS-DG-209; Unit 2 Integrated Division I Response Time Surveillance; Revision 1
- LOS-DG-210; Unit 2 Integrated Division II Response Time Surveillance; Revision 1
- LOS-DG-211; Unit 2 Integrated Division III ECCS Response Time Surveillance;
Revision 0
- LOS-SC-R5; SBLC Pump Full Flow/Pressure Test; Revision 2
- LOS-SC-Q1; SBLC Pump Operability/Inservice Test and Explosive Valve Continuity
Check; Revision 21
- LMP-SC-01; SBLC Explosive Valve Maintenance; Revision 14
- LTS-100-3; Main Steam Isolation Valve Local Leak Rate Test; Revision 17
- LTS-100-10; Inboard/Outboard Feedwater Check Valves and Outboard Stop Valves
Local Leak Rate Test; Revision 17
- LTS-300-5; Primary Containment Leak Rate Testing Program; Revision 35
- LTS-900-6; RHR Shutdown Cooling Return Pressure Isolation Valve Water Leak Rate
Test; Revision 19
- LTS-900-12; RHR Primary Isolation Valve Water Leak Rate Test; Revision 19
Sodium Pentaborate Sample Results for Unit 1 and Unit 2 SBLC Storage Tanks;
June 2004 - December 2004
Work Orders:
- 606950-01; OP Integrated Divisional Response Time Test IAW LOS-DG-210;
2/25/2005
- 607327-01; LOS-DG-209 Integrated Div 1 ECCS Response Time Pumps and Diesel;
2/23/2005
- 608104-01; LOS-DG-211 Integrated Div 3 ECCS Response Time Pumps and Diesel;
2/20/2005
- 759299-01; OP LOS-SC-Q1 2A SBLC Pump Quarterly Att 2A; 3/4/2005
1R23 Temporary Plant Modifications
10 CFR 50.59 Safety Evaluations:
- L01-0227; TMOD for an Alternate Means of Measuring the DW Floor Drain Sump Flow
Rate; Revision 1
Corporate RCR 299641; Single Failure Vulnerability of Safety Related Division 1 & 2
Protective Relay Circuitry Root Cause Analysis; 3/8/2005
Issue Reports:
- 286665; Stem to Disc Separation on 1DG032; 12/30/2004
- 287208; DWFDS Fillup Rate High; 1/03/2005
- 290618; CSCS Valve PMs Critical Prior to L1R11 Need Deferral; 1/13/2005
14 Attachment
- 290678; Noble Gas Channel Alarm Will Not Clear; 1/14/2005
- 291499; DWFDS Fillup Rate Reading 1.1 GPM; 1/18/2005
- 292281; Div 1 125 VDC Transient During Charger Swap; 1/19/2005
- 293279; U-1 DWFD FUR 1UR-RF002 Pen 1 Ind > 1 GPM Above Alternate; 1/22/2005
- 293389; LOP-DC-01 Revision; 1/23/2005
- 295228; Hi Voltage During U2 Division 1 Charger Swap;1/28/2005
- 297076; Vulnerability of Division 1 & 2 Protective Relay Circuitry; 2/4/2005
- 297795; Difference in 125VDC Divisional Charger Metering; 2/4/2005
- 299188; Lack of Minimum 6-inch Physical Separation in Division 1 & 2 CTs; 2/8/2005
Engineering Change Requests:
- 352281; Provide Information in Eng Change or Equivalent on Delta Between V-Notch
and the Totalizer; 10/09/2001
- 368281; Battery Charger Troubleshooting as an Intermittent Load; 1/21/2005
Engineering Changes:
- 340584; Evaluate Acceptability of Energizing Both 125 VDC Division 1 or 2 Battery
Chargers Simultaneously to Support Battery Charger Testing; Revision 0
- 346528; Provide Guidance for the Use of Intermittent Loads; Revision 0
- 353125; Removal of Disc From Valve 1DG032; Revision 0
- 353657; Isolation of Metering to Common 141Y/142Y and 241Y/242Y Safety Related
Buses; Revision 0
Operability Evaluations:
- OE 02-008; Plugging of Unit 2 Drywell Floor Drain Effects on Leak Detection
Instrumentation; Revision 0
- OE 05-001; Minimum 6-inch Physical Separation in Division 1 & 2 CTs; Revision 0
Procedures:
- CC-AA-308; Control and Tracking of Electrical Load Changes; Revision 4
- LES-DC-103A; Division I Battery Charger Capacity Test; Revision 11
- LOR-1PM13J-A301; Drywell Floor Drain Sump Level Hi, Hi Hi, or Pump Start Failure;
Revision 4
- LOS-AA-S101; Unit 1 Shiftly Surveillence; Revision 28
Temporary Configuration Change:
- 353167; Install Alternate Method of Determining DWFDS Flow Rate; 1/24/05
1EP2 Alert and Notification System (ANS) Testing
Procedures:
- EP-AA-125-1004; Emergency Response Facilities and Equipment Performance
Indicator Guidance; Revision 3
LaSalle County Station Design Study for Total EPZ Siren Coverage; January 2002
LaSalle County Station Off-Site Siren Test Plan; Revision 4; December 2002
15 Attachment
Warning System Maintenance and Operational Reports for LaSalle County Station:
- January 8, 2003 through February 28, 2003
- February 11, 2004 through March 2, 2004
Siren Operations Manual - LaSalle County; February 28, 2003
Exelon Semi-Annual Siren Reports For LaSalle County Station:
- January 1, 2003 through June 30, 2003
- July 1, 2003 through December 31, 2003
- January 1, 2004 through June 30, 2004
Issue Reports:
- 206404; Review of Semi-Annual, Non-Scheduled Maintenance Report for First Half
of 2003
- 208758; Review of Semi-Annual, Non-Scheduled Maintenance Report for Second Half
of 2003
1EP3 Emergency Response Organization (ERO) Augmentation Testing
Procedures:
- EP-AA-112-100; Control Room Operations; Revision 7
- EP-AA-112-100-F-01; Shift Emergency Director Checklist; Revision B
- EP-AA-112-100-F-06; Midwest ERO Augmentation; Revision C
- EP-AA-122-1001; Attachment 2; Conduct of Call-In Augmentation Drills; Revision 3
LaSalle County Station ERO Off-Hours, Unannounced, Off-Hours Augmentation Call-In
Drill Records; April 2004 through January 2005
LaSalle Station ERO Roster; Teams A through D and Back-ups; March 2005
Random Sample of 30 LaSalle County Station ERO Members' EP Training Records
Issue Reports:
- 217626; Paging Concerns in April 2004 Augmentation Drill
- 221122; Paging Concerns in May 2004 Augmentation Drill
- 236587; Three On-call ERO Did Not Receive Page in July 2004 Drill
- 262750; Paging Concerns in October 2004 Augmentation Drill
- 275140; Two ERO Members Did Not Receive Page in November 2004 Drill
- 282734; Four ERO Members Did Not Receive Page in December 2004 Drill
- 292460; Three ERO Members Did Not Receive Page in January 2005 Drill
- 262750; Evaluation of ERO Response Problems During Monthly Augmentation Drills
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies
Procedures:
- EP-AA-122; Drills and Exercises; Revision 4
- EP-AA-122-1001; Drill Development, Conduct, and Evaluation; Revision 4
16 Attachment
Internal Memorandums:
- Mini-Drill Findings and Observation Report for Four Drills in August 2003;
September 2, 2003
- October 2003 Mini-Drill Findings and Observation Report; October 24, 2003
- LaSalle County Station 2003 Medical Drill Findings and Observation Report;
January 5, 2004
- LaSalle 2004 NRC Graded Exercise Findings and Observation Report; April 9, 2004
- May 19 and June 2, 2004 Mini-Drills Findings and Observation Report; June 3, 2004
- LaSalle County Station June 28, 2004 Unusual Event Critique Report; July 26, 2004
- July 29 and August 5, 2004 Mini-Drills Findings and Observation Report;
August 11, 2004
- December 9 and December 16, 2004 Mini-Drills Findings and Observation Report;
December 30, 2004
- LaSalle County Station 2004 Medical and Health Physics Drill Findings and
Observation Report; December 20, 2004
Nuclear Oversight Reports:
- Emergency Preparedness 50.54(t) and Meteorology Audit Report LAS-04-03;
Performed on April 12 through 16, 2004; April 22, 2004
- Objective Evidence Report LS-04-3Q; ERO Staffing and Awareness of
Fitness-for-Duty Expectations
- Objective Evidence Report LS-04-4Q; Observations of Two Mini-Drills and Medical Drill
in December 2004
Root Cause Investigation Report; Emergency Plan Radiation Protection On-Shift
Requirement Not Met Due to Lapsed Radiation Protection Qualifications of Chemistry
Technicians; December 3, 2004
Issue Reports:
- 178665; NOS Observations of December 2003 Medical Drill
- 190290; NOS Observations During February 2004 Drill and March 2004 Exercise
- 202751; February 2004 Drill Scenario Validation Concerns
- 207883; Three Concerns on Performance of In-Plant Teams' Controllers During
March 2004 Exercise
- 207887; March 2004 Exercise Scenario Development and Control Weaknesses
- 207890; Warning Onsite Personnel Objective Failed During March 2004 Exercise
- 209239; Re-assess Seismic Monitor Set Point Value in Emergency Action Level HU-4
- 214187; Slow Decision Making to Authorize Potassium Iodide to Affected On-site
Personnel During March 2004 Exercise
- 214200; Operations Support Center ERO Performance Concerns During March 2004
Exercise
- 215285; Several Emergency Plan Elements Not Tested in Five-Year Period
- 215362; Some Recreational Facilities Within the EPZ Did Not Have Posted Emergency
Information
- 216385; No Actions Planned for ERO Pagers' "Dead Zones"
- 232858; Notification Performance Improvement Opportunities from June 2004 Actual
Unusual Event Response
- 241268; Resident Inspector Noted Failure to Consider Applicability of a Heat Stress
Procedure During a July 2004 Drill
17 Attachment
- 257638; On-Shift ERO Staffing Concern - Training of Chemistry Technicians Versus
Training Of Radiation Protection Technicians
- 264105; NOS Concern on Critique When 2004 Medical Drill was Suspended
- 273813; Technical Support Center's Particulate, Iodine, and Noble Gas Monitor is Out
of Calibration and Back-up Monitor Not Adequate
Training Request 04-402; Additional Training on Notification Timeliness
NRC Event Report 40845; Unusual Event Declared Due to Earthquake Registered at
LaSalle County Station
Required Reading Packages:
- ERO Package on February 2004 Drill and March 2004 Exercise
- Shift Managers Package on Warning Onsite Personnel Concerns During March 2004
Exercise
- ERO Package on Operations Support Center Staff's Performance Concerns During
March 2004 Exercise
Corporate Action Requests:
- 5040EP; Corporate EP Staff Revise ERO Training Procedure to Increase Level of
Detail on ERO Training of Radiation Protection Versus Chemistry Technicians
- 8007EP; Corporate EP Staff Assess Process to Determine Qualification Requirements
of ERO Members Whose ERO Training Includes Accredited Training Performed by
Other Departments
2OS1 Access Control to Radiologically Significant Areas
Access Control to Radiologically Significant Areas and Occupational Exposure Control
Effective Performance Indicator; September 30, 2005
Issue Reports:
- 261792; Access Control Focused Area Self-Assessment; 10/8/2004
- 282460; TLD Run Through X-Ray Machine; 12/13/2004
- 291904; Exceeded Dose Allotted for Coil Cleaning; 1/19/2005
- 293751; Unexpected High Dose-Rate on Radwaste Container; 1/24/2005
- 294919; Venture Scaffold Carpenters Contaminated; 1/25/2005
- 297958 Venture Carpenter - Electronic Dosimeter Dose Rate Alarm; 2/4/2005
- 298702; Radworker Human Performance Issue; 2/7/2005
- 299284; Dose Rate Alarm Received While Hanging Lead in 2B RHR; 2/14/2005
- 299670; (NOS ID) Radiation Protection Improper Posting on the Turbine Deck;
2/9/2005
- 299705; Failure to Obtain Thermoluminescent Detector Prior to Working in
Radiologically Controlled Area; 2/9/2005
- 299750; Dose Rate Alarm Received During Shielding Installation; 2/9/2005
- 300861; Electronic Dosimeter Dose Rate Alarms in 678 Turbine Building Main Steam
Tunnel; 2/13/2005
- 299763; Dose Rate Alarm Received During Shielding Installation; 2/9/2005
- 301189; Unexpected Dose Rate Alarm - Venture Pipefitter; 2/19/2005
- 301225; Contaminated Area Reach-In - Venture Worker; 2/19/2005
18 Attachment
- 301798; Prompt Investigation Report of PN Services Workers Cut Vent Hose on
Refuel Floor; 2/15/2005
Procedures:
- MA-AA-716-010; Maintenance Planning; Revision 4
- MA-MW-716-010-1000; Passport Work Planning Manual; Revision 4
- RP-AA-461; Radiological Controls for Contaminated Water Diving Operations;
Revision 0
2OS2 As Low As Is Reasonably Achievable Planning And Controls (ALARA)
Issue Reports:
- 300541; RQP Hold Released By Non-Radiation Protection Person; 2/11/2005
- 300710; Work Order RQP Hold Bypassed; 2/12/2005
- 300730; LaSalle Permitting Low Standards of Work, Ineffective Corrective Actions;
2/12/2005
Procedures:
- RP-AA-376-1001; Radiological Posting, Labeling, and Marking Standard; Revision 2
- RP-AA-401; Operational ALARA Planning and Controls; Revision 4
Radiation Work Permits:
- 10004000; L2R10 Temporary Shielding in the Drywell; Revision 2
- 10004003; L2R10 Scaffold Activities in the Drywell; Revision 0
- 10004016; L2R10 CRD Pull and Put; Revision 2
- 10004057; L2R10 Unit 2 Reactor Suppression Pool Activities and Support; Revision 0
- 10004088; Unit 2 Reactor Vessel Disassembly and Reassembly; Revision 1
- 10004792; L2R10 Chemical Decon Drywell Work/Unit 2 RB 774'; Revision 0
4OA1 Performance Indicator Verification
Procedures:
- EP-AA-125-1002; ERO Performance; Revision 3
- EP-AA-125-1003; ERO Readiness; Revision 4
- EP-AA-125-1004; Emergency Response Facilities and Equipment; Revision 3
- LS-AA-2110; Monthly Data Elements for NRC ERO Drill Participation; January 2004
through December 2004; Revision 6
- LS-AA-2120; Monthly Data Elements for NRC Drill and Exercise Performance;
January 2004 through December 2004; Revision 4
- LS-AA-2130; Monthly Data Elements for NRC ANS Reliability; January 2004 through
December 2004; Revision 4
Siren Reports:
- Daily Reports; January 1, 2004 through December 31, 2004
- Monthly Operability Reports; January 2004 through December 2004
Required Reading Package; Protective Action Recommendation Development; dated
June 2004
19 Attachment
Issue Reports:
- 241955; Failure to Classify an Alert During August 2004 Drill
- 242469; Inaccurate Emergency Class on Notification Form During August Drill
- 242025; Incorrect Protective Action Recommendation Developed During a Drill
- 249574; Adverse Trend in DEP Performance Indicator in Fourth Quarter 2004
- 283475; Failure to Classify an Alert 15 Minutes During December 9, 2004, Drill
- 283601; Inaccurate Notification Form Completed During December 16, 2004, Drill
- 306946; NOS Identified Minor Error with Reported DEP PI Opportunities for Fourth
Quarter 2004
4OA2 Identification and Resolution of Problems
Procedures:
- CC-AA-201; Plant Barrier Control Program; Revision 5
- OP-MW-201-004; Fire Prevention for Hot Work; Revision 0
- OP-MW-201-007; Fire Protection System Impairment Control; Revision 3
- OP-AA-201-001; Fire Marshal Tours; Revision 2
- OP-AA-201-008; Pre-Fire Plans; Revision 1
- OP-AA-201-009; Control of Transient Combustible Material; Revision 4
Issue Reports:
- 280218; 2A Diesel Generator Trip on Reverse Power; 12/07/2005
- 302209; Small Fire in Unit 2 Reactor Building - 694 Elevation; 2/16/2005
- 302447; Near Miss - Fire Extinguisher Malfunction; 2/16/2005
- 304516; (NRC Identified) RHR Keep Fill Modification Fire Protection Awareness;
2/23/2005
4OA3 Event Follow-up
Corporate RCR 299641; Single Failure Vulnerability of Safety Related Division 1 & 2
Protective Relay Circuitry Root Cause Analysis; 3/8/2005
RA05-25; License Condition 2.F(a) Report: Exceeding License Condition 2.C(1);
3/9/2005
Issue Reports:
- 297076; Vulnerability of Division 1 & 2 Protective Relay Circuitry; 2/4/2005
- 299188; Lack of Minimum 6-inch Physical Separation in Division 1 & 2 CTs; 2/8/2005
- 304613; Controller Failed High; 2/23/2005
- 304789; Failure of 1HK-RR023 Results in Unit 1 Operation Greater Than 100 % RTP;
2/23/2005
- 305612; Evaluation of Operations Crew Performance - RR FCV Failure; 2/25/2005
- 307523; Problem with Re-Flash Function for SPDS Button on PPC; 3/2/2005
- 307654; Evaluate LOA-RR-101(102) for Possible Revision; 3/2/2005
- 307657; U1 PPC Alarm Program May Prevent Audible Alarm; 3/2/2005
- 307659; U2 PPC Alarm Program May Prevent Audible Alarm; 3/2/2005
20 Attachment
Operability Evaluation:
- OE 05-001; Minimum 6-inch Physical Separation in Division 1 & 2 CTs; Revision 0
Engineering Change:
- EC 353657; Isolation of Metering to Common 141Y/142Y and 241Y/242Y Safety
Related Buses; Revision 0
21 Attachment
LIST OF ACRONYMS USED
ACE Apparent Cause Evaluation
ALARA As-Low-As-Is-Reasonably-Achievable
ANS Alert and Notification System
APRM Average Power Range Monitor
ARM Area Radiation Monitor
ASME American Society of Mechanical Engineers
CAP Corrective Action Program
CAR Corrective Action Request
CCA Common Cause Analysis
CFR Code of Federal Regulations
CIV Containment Isolation Valves
CR Condition Report
CRD Control Rod Drive
CRS Control Room Supervisor
CSCS Core Standby Cooling System
CT Current Transformer
CW Circulating Water
CY Calendar Year
DC Direct Current
DG Diesel Generator
DGN Diesel Generators
DRP Division of Reactor Projects
DW Drywell
ECCS Emergency Core Cooling System
ED Electronic Dosimeter
EDG Emergency Diesel Generator
EPZ Emergency Preparedness Planning Zone
ERO Emergency Response Organization
ES Engineered Safeguards
FC Fuel Pool Cooling
FCV Flow Control Valve
HEPA High Efficiency Particulate Air
I&C Instrumentation and Controls
IMC Inspection Manual Chapter
IP Inspection Procedure
IR Inspection Report or Issue Report
ISI Inservice Inspection
IST Inservice Test
kV Kilovolt
kW Kilowatts
kVAR Kilovolts-Amperes-Reactive
LPCS Low Pressure Core Spray
LOCA Loss of Coolant Accident
mrem Millirem
22 Attachment
msec Millesecond
MWth Megawatts Thermal
NCV Non-Cited Violation
NEI Nuclear Energy Institute
NLO Non-Licensed Operator
NRC U.S. Nuclear Regulatory Commission
NSO Nuclear Station Operator
OWA Operator Workaround
PI Performance Indicator
PI&R Problem Identification and Resolution
PRM Process Radiation Monitors
RA Required Actions
RCA Radiologically Controlled Area
RCIC Reactor Core Isolation Cooling
RCR Root Cause Report
RCR Root Cause Review
RFO Refueling Outage
RHRSW Residual Heat Removal Service Water
RO Reactor Operator
RP Radiation Protection
RPS Radiation Protection Specialist
RPT Radiation Protection Technician
RR Reactor Recirculation
RWP Radiation Work Permit
SAT Station Auxiliary Transformer
SBGT Standby Gas Treatment
SDP Significance Determination Process
SRA Senior Reactor Analyst
SRO Senior Reactor Operator
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
Vac Volts Alternating Current
Vdc Volts Direct Current
VY Ventilation System
23 Attachment