ML030280343
| ML030280343 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 01/27/2003 |
| From: | Ring M NRC/RGN-III/DRP/RPB1 |
| To: | Skolds J Exelon Generation Co |
| References | |
| IR-02-008 | |
| Download: ML030280343 (54) | |
See also: IR 05000254/2002008
Text
January 27, 2003
Mr. John L. Skolds, President
Exelon Nuclear
Exelon Generation Company, LLC
Quad Cities Nuclear Power Station
4300 Winfield Road
Warrenville, IL 60555
SUBJECT:
QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2
NRC INTEGRATED INSPECTION REPORT 50-254/02-08; 50-265/02-08
Dear Mr. Skolds:
On December 28, 2002, the U. S. Nuclear Regulatory Commission (NRC) completed an
integrated inspection at your Quad Cities Nuclear Power Station, Units 1 and 2. The enclosed
report documents the inspection findings which were discussed on December 31, 2002, with
Mr. Tulon and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, the inspectors identified seven issues of very low safety
significance (Green). Three of these issues were determined to involve violations of NRC
requirements. However, because of their very low safety significance and because they have
been entered into your 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.
If you contest the subject or severity of a Non-Cited Violation, you should provide a response
within 30 days of the date of this inspection report, with the basis for your denial, to the
U.S. Nuclear Regulation Commission, ATTN: Document Control Desk, Washington, DC
20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission -
Region III, 801 Warrenville Road, Lisle, IL 60532-4351; the Director, Office of Enforcement,
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident
Inspector Office at the Quad Cities Nuclear Power Station.
Since the terrorist attacks on September 11, 2001, the NRC has issued two Orders (dated
February 25, 2002, and January 7, 2003) and several threat advisories to licensees of
commercial power reactors to strengthen licensee capabilities, improve security force
readiness, and enhance access authorization. The NRC also issued Temporary Instruction
2515/148 on August 28, 2002, that provided guidance to inspectors to audit and inspect
licensee implementation of the interim compensatory measures (ICMs) required by the
February 25th Order. Phase 1 of TI 2515/148 was completed at all commercial nuclear power
J. Skolds
-2-
reactors during calendar year (CY) 02, and the remaining inspections are scheduled for
completion in CY 03. Additionally, table-top security drills were conducted at several licensees
to evaluate the impact of expanded adversary characteristics and the ICMs on licensee
protection and mitigative strategies. Information gained and discrepancies identified during the
audits and drills were reviewed and dispositioned by the Office of Nuclear Security and Incident
Response. For CY 03, the NRC will continue to monitor overall safeguards and security
controls and conduct inspections, and will resume force-on-force exercises at selected power
plants. Should threat conditions change, the NRC may issue additional Orders, advisories, and
temporary instructions to ensure adequate safety is being maintained at all commercial nuclear
power reactors.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) component of NRC's
document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Mark A. Ring, Chief
Branch 1
Division of Reactor Projects
Docket Nos. 50-254; 50-265
Enclosure:
Inspection Report 50-254/02-08; 50-265/02-08
See Attached Distribution
DOCUMENT NAME: G:\\quad\\ML030280343.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
RIII
NAME
PPelke:dtp
MRing
DATE
01/24/03
01/27/03
OFFICIAL RECORD COPY
J. Skolds
-3-
cc w/encl:
Site Vice President - Quad Cities Nuclear Power Station
Quad Cities Nuclear Power Station Plant Manager
Regulatory Assurance Manager - Quad Cities
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 - Dresden and Quad Cities
Senior Counsel, Nuclear, Mid-West Regional
Operating Group
Document Control Desk - Licensing
Vice President - Law and Regulatory Affairs
Mid American Energy Company
M. Aguilar, Assistant Attorney General
Illinois Department of Nuclear Safety
State Liaison Officer, State of Illinois
State Liaison Officer, State of Iowa
Chairman, Illinois Commerce Commission
W. Leach, Manager of Nuclear
MidAmerican Energy Company
J. Skolds
-4-
ADAMS Distribution:
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
50-254; 50-265
License Nos:
Report No:
50-254/02-08; 50-265/02-08
Licensee:
Exelon Nuclear
Facility:
Quad Cities Nuclear Power Station, Units 1 and 2
Location:
22710 206th Avenue North
Cordova, IL 61242
Dates:
October 1 through December 28, 2002
Inspectors:
K. Stoedter, Senior Resident Inspector
M. Kurth, Resident Inspector
J. House, Radiation Protection Inspector
D. Jones, Engineering Inspector
R. Kopriva, Senior Project Engineer, Region IV
P. Lougheed, Engineering Inspector
D. Nelson, Radiation Protection Inspector
P. Pelke, Reactor Engineer
G. Pirtle, Physical Security Inspector
T. Ploski, Senior Emergency Preparedness Inspector
S. Sheldon, Engineering Inspector
T. Steadham, Reactor Engineer
Approved by:
Mark Ring, Chief
Branch 1
Division of Reactor Projects
2
SUMMARY OF FINDINGS
IR 05000254/2002-008, 05000265/2002-008; Exelon Nuclear; on 10/01-12/28/02, Quad Cities
Nuclear Power Station; Units 1 & 2. Adverse Weather, Refueling and Outage Activities,
Identification and Resolution of Problems, and Event Followup.
This report covers a 3-month period of baseline resident inspection and announced baseline
inspections on Temporary Instruction 2515/148, radiation protection, inservice inspection, and
emergency preparedness. The inspection was conducted by regional inspectors and the
resident inspectors. Three Severity Level IV Non-Cited Violations (NCV) and seven Green
Findings were identified. The significance of most findings is indicated by their color (Green,
White, Yellow, Red) using Inspection Manual Chapter 0609, Significance Determination
Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a
severity level after NRC management review. The NRCs program for overseeing the safe
operation of commercial nuclear power reactors is described in NUREG-1649, Reactor
Oversight Process, Revision 3, dated July 2000.
A.
Inspector-Identified and Self-Revealing Findings
Cornerstone: Initiating Events
Green. The failure to identify the proper plant air supply prior to installing moisture
separator decontamination equipment (air powered vacuum) resulted in two unexpected
instrument air system transients on October 14 and 15, 2002. The work package did not
contain equipment identification numbers to aid in identifying the proper air supply. In
addition, the individual instructed to identify the air supply failed to perform self-checking
activities that could have identified the inappropriate selection of instrument air for the
equipment installation rather than service air.
This finding was more than minor because it affected the loss of instrument air initiating
event frequency. The finding was of very low safety significance because the exposure
time was short and all mitigating systems needed to address a loss of instrument air
were available. No violation of NRC requirements occurred due to the instrument air
system being non-safety-related. (Section 1R20.1)
Green. The failure to adequately correct deficiencies in the 1B reactor recirculation
motor generator voltage regulator resulted in a pump trip and power transient on
December 6, 2002. On November 29 and December 3, the licensee initiated two
condition reports due to the motor generator voltage regulator failing to meet acceptance
criteria during tuning activities. The inspectors determined that the licensee had not
adequately considered changes made to the voltage regulator during the outage and
power ascension which resulted in inappropriately concluding that the failure to meet the
acceptance criteria was acceptable.
This finding was determined to be more than minor because the reactor recirculation
pump trip was a precursor to a significant transient. This finding was considered to be of
very low safety significance since it did not: contribute to the likelihood of both a reactor
trip and that mitigating equipment would not be available, contribute to the likelihood of a
3
loss of coolant accident, increase the likelihood of a fire or flood, or increase the
frequency of core damage scenarios using other plant specific analyses.
(Section 4OA2.1)
Cornerstone: Mitigating Systems
Green. A self-revealing failure occurred on October 16, 2002, when the safe shutdown
makeup pump room cooler strainer became clogged with duck weed. The inspectors
determined that twice per shift rounds to verify strainer operability and multiple strainer
cleanings were not effective in ensuring continued operability of this equipment. In
addition, control room personnel were not immediately notified of the clogged strainer via
a control room alarm or a local alarm due to a system design deficiency.
This finding was more than minor because the strainer clogging impacted the operability
of the safe shutdown makeup pump which can be used when responding to initiating
events. In addition, the system design issues created a situation where operations
personnel were unaware of equipment operability issues. This finding was of very low
safety significance because the total exposure time was short, all other mitigating
systems were available, and the safe shutdown makeup pump could have been
recovered if needed. No violation of NRC requirements occurred due to the safe
shutdown makeup only being of augmented quality per the licensees Quality Assurance
Report. (Section 1R01.2)
Green. During the 1A stator water heat exchanger tube bundle replacement on
November 11, 2002, approximately 200 gallons of water were released as the tube
bundle was pulled from the heat exchanger. The water migrated to the Unit 1 emergency
diesel generator room below and tripped the circulating oil pump and turbocharger
lubricating oil pump rendering the diesel inoperable. The work package used to perform
the work did not contain information regarding the large amounts of water that may be
present in the heat exchanger. In addition, information regarding the amount of water
present in the heat exchanger was not communicated to the contractors performing the
work even though this information was well known by operations and maintenance
personnel.
This finding was more than minor because the inadequate work instructions and poor
communications resulted in a situation which impacted the operability, availability, and
reliability of the emergency diesel generator. The finding was of very low safety
significance since the loss of the emergency diesel generator did not result in an actual
loss of safety function of a system and did not result in an actual loss of safety function of
a single train for greater than the Technical Specification Allowed Outage Time. No
violations of NRC requirements were identified due to the stator water heat exchanger
being non-safety-related. (Section 1R20.2)
Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion V, due to the failure to adhere to procedural requirements regarding the
erection of scaffolding near safety-related equipment. On November 6, 2002, the
inspectors identified numerous examples where scaffolding was in contact with residual
heat removal system piping and valves.
4
This finding was more than minor since multiple examples of scaffolding erection
deficiencies were identified which indicated that workers routinely failed to follow
scaffolding erection procedural requirements. This finding was determined to be of very
low safety significance since the scaffolding did not result in an actual loss of safety
function of any system. (Section 1R20.4)
Green. A loose wire caused a condition that would have resulted in the failure of the 2B
residual heat removal system to automatically start when required and would have
resulted in the diversion of water from the 2A residual heat removal system if an
emergency core cooling system actuation signal was received while the 2B residual heat
removal system was operating in torus cooling. One Non-Cited Violation of Technical Specification 3.5.1 was identified. The licensee determined that the wire was loosened
during the February 2002 refueling outage. The impact of the loose wire was not
addressed until October 2002 even though unexpected equipment performance was
experienced on three previous occasions.
This finding was more than minor since the loose wire impacted the operability,
availability, reliability, and capability of the residual heat removal system. The finding
was determined to be of very low risk significance since the both trains of the residual
heat removal system were recoverable using simple operator actions and all remaining
mitigating systems equipment were available. (Section 4OA3.2)
Cornerstone: Barrier Integrity
Green. The failure to adhere to procedure precautions and perform timely control room
panel monitoring resulted in the inadvertent isolation of the reactor water cleanup system
while the system was being used to remove decay heat from the Unit 1 reactor vessel. A
Non-Cited Violation of Technical Specification 5.4.1 was identified.
This finding was determined to be more than minor because the isolation impacted the
reactor water cleanup systems continued ability to provide cooling of the reactor fuel and
fuel cladding while the Unit 1 reactor was in a shutdown condition. The finding was of
very low safety significance since the isolation did not significantly degrade the licensees
ability to recover decay heat removal through the use of the reactor water cleanup or
residual heat removal systems once the isolation occurred. (Section 1R20.3)
B.
Licensee-Identified Violations
Licensee-Identified Violations of very low safety significance have been reviewed by the
inspectors. Corrective actions taken or planned by the licensee have been entered into
the corrective action program. These violations and corrective action tracking numbers
are listed in Section 4OA7 of this report.
5
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period operating at reduced power levels due to entering
coastdown. On November 5 operations personnel shut down Unit 1 and began a refueling
outage. Major activities accomplished during the outage included implementation of an
extended power uprate, replacement of the high pressure turbine rotor, modifications to the
reactor steam dryer, installation of new condensate demineralizers, and upgrading the high and
low pressure feedwater heaters. Unit 1 achieved criticality on November 25 and was
synchronized the grid the following day. On December 2 the licensee began power uprate
testing. During the multi-day testing evolution, an unisolable leak developed on the 1B reactor
feedwater pump. Operations personnel lowered reactor power to 85 percent to complete the
leak repairs. On December 6 the operators restored reactor power to 94 percent and began
additional power uprate testing. Upon reaching 97 percent power, the 1B reactor recirculation
pump tripped due to motor generator set overcurrent on two out of three phases. The pump
trip resulted in reducing reactor power to approximately 35 percent. The licensee completed
repairs to the reactor recirculation pump on December 9 and continued with the power
ascension. Unit 1 achieved and maintained the maximum post-extended power uprate power
level on December 11. Engineering and operations personnel completed all required power
uprate testing later the same week.
Unit 2 entered the inspection period operating at the maximum achievable power level. On
October 7 operations personnel lowered reactor power to approximately 80 percent to repair a
leak on the 2A reactor feedwater pump suction relief valve. Unit 2 returned to its maximum
power level on October 9. On November 8 and December 5, operations personnel lowered
reactor power to approximately 85 percent to conduct turbine valve testing. In both cases the
unit was returned to maximum power levels within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
1.
REACTOR SAFETY
Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1
Routine Cold Weather Preparations
a.
Inspection Scope
From October 29 through November 1, 2002, the inspectors assessed the stations
readiness for cold weather conditions by conducting detailed inspections on the ice melt
valve and the heat tracing system. The inspectors chose the ice melt valve for inspection
due to its importance in preventing the freezing of water for the service water, circulating
water, fire water, residual heat removal service water and emergency diesel generator
service water systems. The heat tracing system was chosen because of its importance
in maintaining the operability of safety-related piping exposed to extreme temperature
conditions. The inspectors reviewed the Updated Safety Analysis Report, and seasonal
6
readiness and adverse weather procedures to determine the operational requirements of
the ice melt valve and heat tracing systems during cold weather conditions. The
inspectors compared this information to the licensees seasonal readiness open items
list, system readiness reports, and open maintenance work requests to ensure that none
of the items on these lists impacted the ability of the ice melt valve and heat tracing
system to perform their intended functions. The inspectors performed a review of
previously initiated condition reports related to cold weather conditions and performed a
plant walkdown to ensure that the items documented in the condition reports had been
appropriately corrected.
b.
Findings
No findings of significance were identified.
.2
Review of Site Specific Weather Condition
a.
Inspection Scope
On October 16, 2002, the safe shutdown makeup pump experienced a self-revealing
failure when the room cooler service water strainer became fouled with duck weed. The
safe shutdown makeup pump system is one of three high pressure systems that can be
used to inject water into the reactor during accident conditions. The safe shutdown
makeup pump is classified as a risk significant system under the Maintenance Rule and
is credited as an injection source in the Appendix R (Fire Protection) Safe Shutdown
Analysis. Between October 16 and November 5, 2002, the inspectors performed an
in-office review of Condition Report 127679, the apparent cause evaluation, operations
logs, and procedures associated with the safe shutdown makeup pump to determine past
system performance and the reason for the failure. The inspectors interviewed
operations, maintenance, and engineering personnel to assess the service water strainer
clogging frequency during increased river debris conditions. The inspectors also
conducted an inspection of the safe shutdown makeup pump room, including the room
cooler and service water systems, to monitor room cooler performance.
b.
Findings
The inspectors identified one Green finding due to an inadequate system design which
prevented operations personnel from immediately discovering that the safe shutdown
makeup pump room cooler service water strainer was clogged with duck weed.
Under normal conditions, operations personnel conducted periodic checks of the safe
shutdown makeup pump room cooler service water duplex strainer. When the duplex
strainers differential pressure reached 10 psid or greater, operations personnel were
required to swap duplex strainers and notify maintenance to clean the fouled strainer.
During increased river debris conditions, operations personnel were required to check the
duplex strainer differential pressure twice per shift.
On October 16, 2002, an operator entered the safe shutdown makeup pump room,
noticed that the room seemed warmer than normal, and that the room cooler was not in
operation. Since the room cooler was needed to support continued operability of the
7
safe shutdown makeup pump, control room personnel entered Technical Specification 3.7.9. Troubleshooting determined that the safe shutdown makeup pump
room cooler was not operating due to the both sides of the service water duplex strainer
being fouled.
The inspectors questioned various personnel to determine why operations was not
immediately notified of the safe shutdown makeup pump room cooler malfunction via a
local or control room alarm. The inspectors were informed that the safe shutdown
makeup pump room cooler circuitry was designed without any local or control room alarm
functions which could be used to notify personnel of equipment malfunctions. Due to this
inadequate design, operations personnel were relying on operator rounds to ensure
continued operability of the safe shutdown makeup pump and its associated support
equipment.
The inspectors determined that the failure to ensure the safe shutdown makeup pump
room cooler circuitry was adequately designed to warn personnel of equipment
malfunctions was more than minor because it: (1) involved the design control and
protection against external factors attributes of the mitigating systems cornerstone; and
(2) affected the cornerstone objective of ensuring the operability, availability, reliability,
and function of a system that responded to initiating events to prevent undesirable
consequences.
The inspectors also determined that this finding should be evaluated using the
significance determination process described in Inspection Manual Chapter 0609,
Significance Determination Process. The inspectors conducted a Phase 1 screening
and determined that a Phase 2 evaluation was required since the strainer clogging and
design inadequacy resulted in an actual loss of safety function of a system.
The inspectors used the risk-informed inspection notebook for Quad Cities Nuclear
Power Station, Units 1 and 2, Revision 1, dated May 2, 2002, to complete the Phase 2
evaluation. The inspectors determined that the exposure time was less than 3 days
since approximately 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> elapsed between the time the room cooler was last
verified to be operable and the time the operator discovered the abnormally warm room.
For each significance determination process worksheet completed, the inspectors
assumed that all mitigating capability was available except for the safe shutdown makeup
pump. The inspectors allowed credit for recovery since the duplex strainer could have
been cleaned, and the room cooler re-started, using manual actions. Using these
assumptions the inspectors evaluated 22 core damage sequences. Worksheet results
ranged from 8 to 18 points. The most dominant core damage sequences involved:
(1) the loss of instrument air with the residual heat removal system available for
containment heat removal; (2) a transient with the loss of the power conversion system
and the automatic depressurization system available; and (3) a loss of service water with
the residual heat removal system available for containment heat removal. The inspectors
concluded that the final significance determination process result for this finding was
8 points; therefore, this finding was considered to be of very low risk significance (Green)
(FIN 50-254/02-08-01; 50-265/02-08-01). The inadequate design issue did not constitute
a violation of NRC requirements since the licensees quality assurance program
considered the safe shutdown makeup pump and its associated support equipment to be
8
of augmented quality. This issue was entered into the licensees corrective action
program as Condition Report 127679.
1R05 Fire Protection (71111.05)
a.
Inspection Scope
During the inspection period, the inspectors conducted in-plant walkdowns of the
following risk-significant fire zones to identify any fire protection degradations:
Fire Zone 8.2.3.A, Unit 1 Turbine Building Control Rod Drive Pumps;
Fire Zone 8.2.6.A, Unit 1 Turbine Building Hallway;
Fire Zone 1.1.1.6, Unit 1/2 Reactor Building Refuel Floor;
Fire Zone 8.2.6.B, Unit 1 Turbine Building Low Pressure Heater Bay;
Fire Zone 11.3.3, Unit 2 Reactor Building Northwest Corner Room, Core Spray;
Fire Zone 11.3.2, Unit 2 Reactor Building Southeast Corner Room, 2B Residual
Heat Removal Room; and
Fire Zone 11.3.4, Unit 2 Reactor Building Northeast Corner Room, 2A Residual
Heat Removal Room.
During the walkdowns the inspectors verified that transient combustibles were controlled
in accordance with the licensees procedures. The inspectors observed the physical
condition of fire suppression devices and passive fire protection equipment such as fire
doors, barriers, and penetration seals. The inspectors observed the condition and
location of fire extinguishers, hoses, and telephones against the Pre-Fire Plan zone
maps. The physical condition of passive fire protection features such as fire doors, fire
dampers, fire barriers, fire zone penetration seals, and fire retardant structural steel
coatings were also inspected to verify proper installation and physical condition.
b.
Findings
No findings of significance were identified.
1R08 Inservice Inspection Activities (71111.08)
a.
Inspection Scope
The inspectors conducted a review of the licensees inservice inspection program for
monitoring degradation of the reactor coolant system boundary and the risk significant
piping system boundaries. Specifically, the inspectors conducted a record review of the
following examinations:
WELD #
SYSTEM
NDE TYPE
High Pressure Coolant Injection
Ultrasonic Testing
High Pressure Coolant Injection
Ultrasonic Testing
Ultrasonic Testing
Ultrasonic Testing
CRDH Pipe-Pipe
Penetrant Testing
9
FW-1
High Pressure Coolant Injection Turbine
Radiographic Testing
These examinations were evaluated for compliance with the American Society of
Mechanical Engineers Boiler and Pressure Vessel Code requirements. The inspectors
also reviewed inservice inspection procedures, equipment certifications, personnel
certifications, and NIS-2 forms for Code repairs performed during the last outage to
confirm that American Society of Mechanical Engineers Code requirements were met.
A sample of inservice inspection related problems documented in the licensees
corrective action program, was also reviewed to assess conformance with 10 CFR
Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. In addition, the
inspectors determined that operating experience was correctly assessed for applicability
by the inservice inspection group.
b.
Findings
The licensee discovered that they had missed inspections of the control rod drive
housing welds (Action Report 00113995). Further discussions of this issue with NRC
staff was documented in Action Report 00132057. This issue will be an Unresolved Item
pending further review of the American Society of Mechanical Engineers Code
requirements (URI 50-254/02-08-02; 50-265/02-08-02).
1R11 Licensed Operator Requalification (71111.11)
a.
Inspection Scope
On October 9, 2002, the inspectors observed an operations crew during a requalification
examination on the simulator using Scenario 00-28, Torus Narrow Range Instrument
Failure, Loss of Coolant Accident Inside Containment, and an Anticipated Transient
Without Scram, Revision 10.
The inspectors evaluated crew performance in the areas of:
clarity and formality of communications;
ability to take timely and conservative actions;
prioritization, interpretation, and verification of alarms;
procedure use;
control board manipulations;
oversight and direction from supervisors; and
group dynamics.
Crew performance in these areas was compared to licensee management expectations
and guidelines as presented in the following documents:
OP-AA-101-111, Rules and Responsibilities of On-Shift Personnel, Revision 0;
OP-AA-103-102, Watchstanding Practices, Revision 0;
OP-AA-103-103, Operation of Plant Equipment, Revision 0;
OP-AA-103-104, Reactivity Management Controls, Revision 0; and
10
OP-AA-104-101, Communications, Revision 0.
The inspectors verified that the crew completed the critical tasks listed in the above
scenario. The inspectors also attended meetings with the licensees evaluators to ensure
that weaknesses noted by the inspectors were noticed by the evaluators and discussed
with the crew.
b.
Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation (71111.13)
a.
Inspection Scope
The inspectors reviewed the documents listed in the List of Documents Reviewed
section of this report to determine if the risk associated with the activities listed below
agreed with the results provided by the licensees risk assessment tool. In each case,
the inspectors conducted walkdowns to ensure that redundant mitigating systems and/or
barrier integrity equipment credited by the licensees risk assessment remained available.
When compensatory actions were required, the inspectors conducted plant inspections
to validate that the compensatory actions were appropriately implemented. The
inspectors also discussed emergent work activities with the shift manager and work week
manager to ensure that these additional activities did not change the risk assessment
results.
Maintenance Activity Assessed
Week Inspected
125 Volt DC Charger Load Testing
December 9, 2002
Risk Associated with U1 High Pressure Coolant Injection Out
of Service Due to Emergent Work
December 9, 2002
U2 Core Spray Semiannual Logic Test
December 9, 2002
b.
Findings
No findings of significance were identified.
1R14 Personnel Performance During Non-routine Plant Evolutions (71111.14)
a.
Inspection Scope
On October 7, 2002, the inspectors observed control room activities associated with a
Unit 2 power reduction to repair a steam leak on a reactor feedwater pump. The
inspectors determined by direct observation and a review of procedural requirements that
reactivity manipulations were verified by a second licensed operator, that operations
personnel were complying with procedures and Technical Specifications, and that plant
11
parameters were as expected for each operating condition.
b.
Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors assessed the following operability evaluations or issues associated with
equipment operability:
Operability Evaluation for Condition Report 124350, Certain General Electric
480 Volt Breakers not Properly Modeled in ELMS-DC Database, dated
September 24, 2002;
Discussions Regarding a Lack of Inservice Inspections on Control Rod Drive
Housing Welds During October and November 2002 (see Condition
Report 132057); and
Operability Evaluation for Condition Report 131936, Potential Failure of
Belleville Springs in Main Steam Isolation Valves 2-0203-2B and 2-0203-2C,
dated November 20, 2002.
The inspectors reviewed the technical adequacy of each evaluation against the Technical
Specifications, the Updated Final Safety Analysis Report, and other design information;
determined whether compensatory measures, if needed, were taken; and determined
whether the evaluations were consistent with the requirements of LS-AA-105,
Operability Determination Process, Revision 0.
In addition, the inspectors reviewed selected issues that the licensee entered into its
corrective action program to verify that identified problems were being entered into the
program with the appropriate characterization and significance.
b.
Findings
No findings of significance were identified.
1R16 Operator Work-Arounds (71111.16)
Semi-Annual Review
a.
Inspection Scope
The inspectors performed a semi-annual review of all operator workarounds and
challenges identified as of October 10, 2002. The inspectors assessed the cumulative
effects of the workarounds and challenges by performing the following:
12
The inspectors compared workaround and challenge information to the normal,
abnormal, and emergency operating procedures to ensure that operations
personnel maintained the ability to correctly respond to plant transients in a
timely manner;
The inspectors utilized system knowledge, a review of plant procedures, and
interviews with operations personnel to ensure that the workarounds and
challenges previously identified did not adversely impact system reliability and
availability, create the potential for system misoperation, or result in a
workaround that impacted multiple mitigating equipment; and
The inspectors reviewed the equipment status tag log, degraded equipment log,
temporary configuration change report, and open operability determination report
for potential operator workarounds and challenges that had not been previously
identified or assessed for potential impact on normal plant operation or transient
response.
In addition to the above, the inspectors reviewed selected issues that the licensee
entered into its corrective action program to verify that identified problems were being
entered into the program with the appropriate characterization and significance.
b.
Findings
No findings of significance were identified.
1R17 Permanent Plant Modifications (71111.17)
a.
Inspection Scope
In October and November 2002, the inspectors reviewed the technical adequacy of
multiple modifications associated with the Unit 1 extended power uprate. A list of the
specific modification packages reviewed is included in the List of Documents Reviewed
section of this report.
The inspectors verified that modification preparation, staging, and implementation did not
impair the operations departments ability to complete emergency and abnormal
operating procedure actions when required, to monitor key safety functions, or to
respond to a loss of key safety functions. The inspectors reviewed the design adequacy
of the modification by verifying the following:
energy requirements were able to be supplied by supporting systems under
accident and event conditions;
replacement components were compatible with physical interfaces;
replacement component properties met functional requirements under event and
accident conditions;
replacement components were environmentally and seismically qualified;
sequence changes remained bounded by the accident analyses and loading on
support systems was acceptable;
13
structures, systems, and components response times were sufficient to serve
accident and event functional requirements assumed by the design analyses;
control signals were appropriate under accident and event conditions; and
affected operations procedures were revised and training needs were evaluated
in accordance with station administrative procedures.
The inspectors also verified that the post modification testing demonstrated system
operability by verifying no unintended system interactions occurred, system performance
characteristics met the design basis, and post-modification testing results met all
acceptance criteria.
b.
Findings
No findings of significance were identified.
1R19 Post Maintenance Testing (71111.19)
a.
Inspection Scope
The inspectors observed and/or reviewed the following post maintenance testing
activities during this inspection period:
Post Maintenance Activity
Date Inspected
Testing Following Modification of the 1A Standby Liquid
Control Pump
October 18, 2002
Testing Following Replacement of the High Pressure
Coolant Injection Turning Gear Time Delay Relay
October 24, 2002
For each post maintenance testing activity selected, the inspectors reviewed the
Technical Specifications and Updated Final Safety Analysis Report against the
maintenance work package to determine the safety function(s) that may have been
affected by the maintenance. Following this review, the inspectors verified that the
licensees post maintenance test procedure adequately tested the safety function(s)
affected by the maintenance, that the procedures acceptance criteria were consistent
with licensing and design basis information, and that the procedure was properly
reviewed and approved. When possible, the inspectors observed the post maintenance
testing activity and verified that the structure, system, or component operated as
expected; test equipment, when used, was adequately calibrated and within its current
calibration cycle; test equipment used was within its required range and accuracy;
jumpers and lifted leads were appropriately controlled; test results were accurate,
complete, and valid; test equipment was removed after testing; and any problems
identified during testing were appropriately documented.
b.
Findings
No findings of significance were identified.
14
1R20 Refueling and Outage Activities (71111.20)
.1
Pre-Outage Work Creates Unexpected Transients in Instrument Air System
a.
Inspection Scope
The inspectors interviewed licensee personnel and reviewed work requests, condition
reports, and procedures to determine the circumstances which led to two unexpected
instrument air transients on October 24 and 25, 2002.
b.
Findings
The inspectors identified one Green finding due to inadequate procedures and the failure
to properly self-check prior to connecting temporary plant equipment to plant air systems.
These deficiencies resulted in two separate instrument air system transients.
On October 14, 2002, a chemistry individual assisted a vendor in routing hoses for the
moisture separator decontamination project by identifying the water and air connections
to be used as directed by Work Order 369947, Task 09. Ten days later, the vendor
directed several pipefitters to connect a decontamination skid to the air and water
connections previously identified. Later the same afternoon, the vendor began using an
air powered vacuum as part of the decontamination activities. Operations personnel
immediately noticed abnormal fluctuations in instrument air pressure but were unaware
an air powered vacuum was being used in the plant. The operators responded to the
pressure fluctuations as required by procedure. However, they were unable to dispatch
individuals to the field to search for the cause of the pressure fluctuations prior to the
fluctuations stopping.
The next morning vendor personnel began using the same air powered vacuum. At
9:05 a.m., control room personnel received an alarm indicating that the Unit 2 backup
service air valve was open. The operators discovered that the Unit 1A and Unit 1/2
instrument air compressors were continuously loaded and instrument air pressures were
noted to be cycling between 91 and 98 pounds per square inch. Control room personnel
dispatched several non-licensed operators and the field supervisor into the plant to
observe air compressor operation and to look for possible air leaks. Operations
personnel also started the Unit 2 instrument air compressor to assist in stabilizing the
Approximately 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after noticing the pressure fluctuations, a non-licensed operator
discovered the vendor using the air powered vacuum. Additional investigation found that
the vacuum had been powered using instrument air rather than service air. The
non-licensed operator stopped the decontamination activities and closed the instrument
air isolation valve. Instrument air pressures returned to normal.
A subsequent interview of the chemistry individual determined that an inadequate work
procedure and improper self-checking contributed to connecting the air powered vacuum
to the instrument air system rather than the service air system. Although Work Order 369947, Task 09, contained steps for the chemistry individual to assist in routing
the hoses, specific equipment identification numbers were not provided. The chemistry
15
individual stated that when he located the service water connection a Chicago fitting was
present on the end of the line to allow the hose to be easily connected to the piping.
When looking for the air connection, the chemistry individual noticed an air valve with a
Chicago fitting installed on the end of the piping. The chemistry individual immediately
assumed that this was the air supply line to be used during the decontamination project.
Although the valve was properly labeled as an instrument air valve, the chemistry
individual failed to check the valve tag.
The inspectors determined that connecting the air powered vacuum to the instrument air
system rather than the service air system was more than minor because it: (1) involved
the configuration control attribute of the Initiating Events cornerstone; and (2) affected
the cornerstone objective of limiting the likelihood of those events that upset plant
stability during power operations. The inspectors also determined that the error by the
chemistry individual affected the cross-cutting area of Human Performance because,
despite the inadequate procedure, the valve was properly labeled and self-checking
should have been used to ensure that the proper air supply was identified.
The inspectors determined that this finding could be assessed using the significance
determination process in accordance with Inspection Manual Chapter 0609, Significance
Determination Process, because the issue was associated with degraded conditions that
could concurrently influence mitigating systems equipment and an initiating event. For
the Phase 1 screening, the inspectors answered yes to Question 2 under the Initiating
Events column which required a Phase 2 evaluation to be performed.
Using the Risk-Informed Inspection Notebook for Quad Cities Nuclear Power Station,
Units 1 and 2, Revision 1, dated May 1, 2002, the inspectors determined that the
findings exposure time was less than three days and that the finding increased the
likelihood of a loss of instrument air. These assumptions resulted in raising the Table 1
likelihood rating for a loss of instrument air by one decade or to a point value of 3. For
the loss of instrument air worksheet, the inspectors determined that all mitigating
systems capability was available. This resulted in four core damage sequences between
7 points and 13 points. The most dominant sequence involved the loss of instrument air
with containment heat removal and long-term venting available. The inspectors
concluded that the final significance determination process result for this finding was
7 points; therefore, this finding was considered to be of very low significance
(FIN 50-254/02-08-03; 50-265/02-08-03). No violation of NRC requirements was
identified due to the instrument air system being non-safety-related. This issue was
placed in the licensees corrective action program via Condition Report 128977.
.2
Stator Water Heat Exchanger Work Leads to Unit 1 Diesel Inoperability
a.
Inspection Scope
The inspectors interviewed licensee personnel and reviewed work instructions and
condition reports to determine the circumstances which led to the unexpected
inoperability of the Unit 1 emergency diesel generator.
16
b.
Findings
The inspectors identified one Green finding due to the use of inadequate stator water
heat exchanger work instructions and weak communications which resulted in rendering
the Unit 1 emergency diesel generator inoperable.
On November 11, 2002, contractor personnel were performing work to replace the
Unit 1A stator water heat exchanger tube bundle. Prior to performing this work,
operations personnel had tagged out the heat exchanger for draining purposes. The
contractors also established funnels and hoses for collecting the several gallons of water
expected to be expelled from the heat exchanger as the tube bundle was removed. As
the contractors began removing the tube bundle from the heat exchanger, a large
amount of water (as much as 200 gallons) was expelled from the heat exchanger and
overwhelmed the funnels and hoses. Within minutes the control room received alarms
indicating a problem with the Unit 1 emergency diesel generator. A local operator
reported that water from the heat exchanger had migrated into the diesel room and
caused the circulating oil pump and the turbocharger lubricating oil pump to trip. Since
the operators were unable to fully determine the extent of the water intrusion, the Unit 1
emergency diesel generator was declared inoperable.
Through interviews the inspectors determined that operations personnel were very aware
that a large amount of water would be expelled from the stator water heat exchanger
when the tube bundle was removed. In fact, the inspectors were informed that this was
the reason that the out of service tagout for the stator water heat exchanger was
considered an exceptional tagout. Operations personnel also told the inspectors that
when mechanical maintenance personnel performed a stator water heat exchanger tube
bundle replacement a large trough was used to catch the water. The inspectors
interviewed the contractor personnel performing the heat exchanger work regarding the
information provided by operations. The contractors stated that they were not made
aware of the possibility for a large amount of water or that a trough had been used
previously to catch the water. The inspectors also reviewed Work Order 99183182,
Task 01, Replace Tube Bundle Assembly in the 1-7401-A Stator Water Heat
Exchanger, and found that the work order specifically stated that the heat exchanger
would be isolated and drained.
The inspectors determined that the failure to have adequate stator water heat exchanger
work instructions, and to communicate information regarding the amount of water, was
more than minor because if left uncorrected the inadequate work instructions could
continue to impact the availability, reliability, and capability of safety-related equipment.
The inspectors also determined that the failure to ensure adequate work instructions
were in place prior to removing the tube bundle also affected the cross-cutting area of
Human Performance. Despite multiple individuals being aware that large amounts of
water would be expelled during this work activity, actions were not taken to communicate
this information to the contractors performing the work.
The Unit 1 emergency diesel generator was normally credited as an emergency power
supply for Unit 1 equipment. At Quad Cities the Unit 1 emergency diesel generator was
also credited as an emergency power source for common equipment such as the
standby gas treatment and control room emergency ventilation systems. When this
17
event occurred, Unit 1 was shut down for a refueling outage. The inspectors reviewed
Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance
Determination Process, Table 1 for a boiling water reactor in refueling operations with
reactor vessel level greater than 23 feet. The inspectors determined that the significance
determination process did not apply since the Unit 1/2 emergency diesel generator
remained available to address accident situations while Unit 1 was shut down. In regards
to Unit 2, the inspectors determined that this issue could be assessed using the At Power
Significance Determination Process in accordance with Inspection Manual Chapter 0609,
Significance Determination Process, because the issue was associated with the
operability, availability, reliability, or function of a system or train in a mitigating system.
The inspectors performed a Phase 1 screening and determined that this issue was of
very low risk significance (Green) since the finding did not represent an actual loss of
safety function of a system or an actual loss of safety function of a single train for greater
than its Technical Specification Allowed Outage Time (FIN 50-265/02-08-04). No
violations of NRC requirements were identified due to the stator water heat exchanger
being non-safety related. This issue was included in the licensees corrective action
program as Condition Report 130694.
.3
Untimely Actions Result in Isolation of Decay Heat Removal System
a.
Inspection Scope
The inspectors interviewed operations personnel and reviewed condition reports and
procedures to determine the circumstances that led to an inadvertent isolation of the
reactor water cleanup system while operating in the decay heat removal mode.
b.
Findings
This self-revealing event led to the identification of one Green finding and a Non-Cited
Violation for the failure to adequately implement QCOP 1200-15, Operation of Decay
Heat Removal Mode of RWCU [Reactor Water Cleanup] System, to ensure that the
reactor water cleanup system did not isolate while being used to remove decay heat from
the Unit 1 reactor vessel.
On November 24, 2002, operations personnel conducted hydrostatic testing on the Unit 1
reactor vessel. Upon completion of this test, operations personnel continued to remove
decay heat from the reactor vessel using the reactor water cleanup system rather than
the shutdown cooling mode of the residual heat removal system. At approximately
2:00 p.m., operations personnel made a control room log entry indicating that the reactor
water cleanup system high temperature alarm and system isolation setpoints were set at
140 degrees as directed by QCOP 1200-13, RWCU System High Temperature Isolation
Setpoint Adjustment. Nine hours later the reactor water cleanup system isolated while
operations personnel were attempting to adjust reactor building closed cooling water
system temperature to maintain reactor vessel water temperature within the specified
temperature band. Operations personnel were able to restart one of the reactor water
cleanup pumps within eight minutes. Heatup of the reactor vessel water was minimal
due to the low amount of decay heat present.
18
The inspectors reviewed QCOP 1200-15 and determined that Step D.2 contained a
precaution warning that the reactor water cleanup system would isolate at 140 degrees if
the reactor building closed cooling water heat removal capabilities were exceeded. The
inspectors determined that operator error and a failure to perform adequate control room
panel monitoring resulted in the failure to control reactor building closed cooling water
temperature and prevent the reactor water cleanup system isolation. The inspectors
determined that this issue was more than minor because it: (1) involved the human
performance attribute of the barrier integrity cornerstone; and (2) affected the
cornerstone objective of providing reasonable assurance that physical design barriers
(fuel cladding, reactor coolant system, and containment) protect the public from
radionuclide releases caused by accidents or events. The inspectors also determined
that the operators error affected the cross-cutting area of Human Performance.
The inspectors determined that this issue could be assessed using the significance
determination process since it was associated with maintaining the integrity of fuel
cladding. Since Unit 1 was shut down when this event occurred, the inspectors reviewed
Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance
Determination Process, Table 1 for a boiling water reactor in cold shutdown or refueling
operation with a time to boil of greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and reactor coolant system level less
than 23 feet above the top of the flange. Page T-21 of Table 1 required two residual heat
removal shutdown cooling subsystems to be operable with one subsystem in operation.
This statement was being met by operating the reactor water cleanup system in the
decay heat removal mode. The inspectors referred to Page T-22 of Table 1 and
determined that the inadvertent isolation of the reactor water cleanup system while in the
decay heat removal mode of operation was of very low risk significance (Green).
Specifically, the isolation did not significantly degrade the licensees ability to recover
decay heat removal once it was lost since the reactor water cleanup system was easily
recoverable and either residual heat removal shutdown cooling subsystem could have
been started to remove decay heat.
Technical Specification 5.4.1 requires that written procedures be established,
implemented, and maintained covering the applicable procedures recommended in
Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 3.c of
Regulatory Guide 1.33 requires instructions for changing modes of operation for the
shutdown cooling system. Contrary to the above, on November 24, 2002, operations
personnel failed to properly implement QCOP 1200-15 to prevent a reactor water
cleanup system isolation which resulted in changing modes of operation for the shutdown
cooling system. This violation is being treated as a Non-Cited Violation consistent with
Section VI.A.1 of the NRCs Enforcement Policy (NCV 50-254/02-08-05). This issue was
entered into the licensees corrective action program as Condition Report 133054.
.4
Scaffold In Contact With Plant Equipment
a.
Inspection Scope
The inspectors conducted periodic tours of plant facilities and identified multiple
examples of outage related scaffolding that was in contact with plant equipment. The
19
inspectors reviewed scaffolding erection procedures to determine if the scaffolding was
constructed in accordance with procedural requirements.
b.
Findings
The inspectors identified one Green Non-Cited Violation due to the failure to follow
procedural requirements regarding the clearances required when erecting scaffolding
near the residual heat removal system.
During a walkdown of the residual heat removal system on November 6, 2002, the
inspectors identified that scaffolding was in contact with safety-related piping and valves.
The inspectors also identified two other examples of scaffolding erection deficiencies
concerning the Unit 1 torus shell and the Unit 1 reactor recirculation motor generator
sets.
The inspectors reviewed Procedure MA-AA-796-024, Scaffold Installation, Inspection,
and Removal, Revision 1, and determined that scaffolding inspectors were required to
verify that scaffolding was not supported by, in contact with or connected to
safety-related equipment. The inspectors notified licensee personnel each time they
identified an example of deficient scaffold erection. The inspectors noted that the
licensee took timely action to address each scaffold erection issue. However, condition
reports were not written for any of the inspector-identified issues. After several
discussions regarding scaffold erection deficiencies during the resident inspectors
weekly management debrief, the licensee initiated Condition Report 131690 on
November 14, 2002, to document the inspector-identified issues and to determine
whether a common cause existed.
The licensee reviewed each scaffolding example and concluded that the equipment
impacted remained operable. Therefore, each example was considered minor.
However, in accordance with Inspection Manual Chapter 0612, Appendix B, Issue
Dispositioning Screening, and Appendix E, Example of Minor Issues, Example 4.a., the
inspectors determined that the improper scaffolding erection was more than minor
because the number of examples identified demonstrated that workers routinely failed to
follow Procedure MA-AA-796-024.
The inspectors determined that this finding could be assessed using the significance
determination process. The inspectors determined that this finding was of very low
safety significance (Green) since the scaffolding erection deficiencies did not result in a
loss of function per Generic Letter 91-18, did not represent an actual loss of safety
function of a system, did not represent an actual loss of safety function of a single train
for greater than its Technical Specification Allowed Outage Time, did not represent an
actual loss of safety function of one or more non-Technical Specification trains of
equipment designated as risk significant per 10 CFR Part 50.65 for greater than
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and did not screen as potentially risk significant due to a seismic, fire, flooding,
or severe weather initiating event.
Criterion V, Instructions, Procedures, and Drawings, of 10 CFR Part 50, Appendix B,
requires that activities affecting quality be performed in accordance with procedures.
Scaffold installation was considered an activity affecting quality and was governed by
20
Procedure MA-AA-796-024. Contrary to the above, on November 6, 2002, the inspectors
identified that the licensee failed to implement Procedure MA-AA-796-024 when erecting
scaffolding near the residual heat removal system. This violation is being treated as a
Non-Cited Violation consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV
50-254/02-08-06). This issue was entered in the licensees corrective action program as
Condition Report 131690.
.5
General Outage Observations
a.
Inspection Scope
The inspectors observed control room activities associated with the shutdown of Unit 1
for a scheduled refueling outage including removing equipment from service, inserting
control rods, completing mode specific surveillance testing, and monitoring reactor
coolant temperature. The inspectors attended daily outage meetings, reviewed outage
control center and control room operator logs, and conducted daily control room tours to
ensure that shutdown safety was maintained throughout the outage, reactor coolant
system instrumentation provided accurate information, the decay heat removal systems
were functioning properly, and inventory and reactivity controls were maintained. The
inspectors conducted periodic observations of outage related work activities to ensure
that work activities were performed in accordance with plant procedures. The inspectors
performed tours of the turbine building, reactor building, and drywell to verify that
procedural requirements regarding fire protection, foreign material exclusion, and the
storage of equipment near safety-related structures, systems, and components were
maintained.
b.
Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors observed surveillance testing activities and/or reviewed completed
surveillance test packages for the tests listed below:
QCOS 6600-49, Division 1 ECCS Automatic Actuation Test;
QCOS 6600-50, Division 2 ECCS Automatic Actuation Test; and
QOS 6500-03, Bus 14-1 Undervoltage Test.
The inspectors verified that the structures, systems, and components tested were
capable of performing their intended safety function by comparing the surveillance
procedure acceptance criteria and results to design basis information contained in
Technical Specifications, the Updated Final Safety Analysis Report, and licensee
procedures. The inspectors verified that the test was performed as written, the test data
was complete and met the requirements of the procedure, and the test equipment range
and accuracy was consistent with the application by observing the performance of the
21
surveillance test. Following test completion, the inspectors conducted a walkdown of the
test area to verify that the test equipment had been removed and that the system was
returned to its normal standby configuration.
b.
Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a.
Inspection Scope
The inspectors reviewed documentation for the following temporary configuration
changes:
Installation of a temporary pump in the Unit 1 drywell equipment drain sump, and
Installation of bladders in the Unit 1 main steam lines to establish secondary
containment.
The inspectors assessed the acceptability of each temporary configuration change by
comparing 10 CFR 50.59 screening and evaluation information against the Updated Final
Safety Analysis Report and Technical Specifications. The comparisons were performed
to ensure that the new configurations remained consistent with design basis information.
The inspectors observed installation and testing of the temporary modifications when
applicable; verified that the modifications were installed as directed; the modifications
operated as expected; modification testing adequately demonstrated continued system
operability, availability, and reliability, and that operation of the modifications did not
impact the operability of any interfacing systems. The inspectors also reviewed condition
reports initiated during or following temporary modification installation to ensure that
problems encountered during installation were appropriately resolved.
b.
Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
a.
Inspection Scope
The inspectors reviewed Revision 15 of the Quad Cities Station Annex to Exelons
Standardized Emergency Plan to determine whether changes identified in Revision 15
reduced the effectiveness of the licensees emergency planning, pending onsite
inspection of the implementation of these changes.
22
b.
Findings
No findings of significance were identified.
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Controls for Radiologically Significant Areas (71121.01)
.1
Plant Walkdowns, Radiological Boundary Verifications and Radiation Work Permit
Reviews
a.
Inspection Scope
The inspectors conducted walkdowns of the radiologically protected area to verify the
adequacy of radiation area boundaries and postings including high and locked high
radiation areas in the Unit 1 and 2 Reactor Buildings including the Unit 1 Drywell, and the
Turbine Building. Confirmatory radiation measurements were taken to verify that these
areas and selected radiation areas were properly posted and controlled in accordance
with 10 CFR Part 20, licensee procedures, and Technical Specifications. The inspectors
walked down areas having the potential for airborne activity and verified the adequacy of
the licensees continuous air monitoring systems and contamination controls. Selected
radiation work permits (RWPs) for radiologically significant work being conducted during
the refueling outage (Q1R17) were reviewed for protective clothing requirements and
electronic dosimetry alarm set points for both dose rate and accumulated dose.
b.
Findings
No findings of significance were identified.
.2
Job-In-Progress Reviews
a.
Inspection Scope
The inspectors observed work occurring on the refueling floor including diving and
refueling operations. Work progress was observed in the reactor building, drywell, low
pressure heater bay and the turbine building. RWP requirements and the As-Low-As-
Reasonably-Achievable (ALARA) briefing packages for selected jobs were reviewed to
assess their adequacy and to determine if job controls were implemented as intended.
The inspectors determined if dosimetry placement, alarm set points, job site radiological
surveys, radiological exposure estimates, contamination controls, airborne monitoring for
radioactive materials, and postings were adequate given the jobs radiological conditions.
b.
Findings
No findings of significance were identified.
23
20S2 ALARA Planning and Controls (71121.02)
.1
Inspection Planning
a.
Inspection Scope
The inspectors reviewed the plants exposure history and trends, its three year rolling
average dose and the impact of source term on radiological exposure under outage
conditions, in order to assess radiological challenges for the current outage. The
licensees processes to estimate and track radiological exposure were discussed with
radiation protection management to determine if the licensees practices were
appropriate.
b.
Findings
No findings of significance were identified.
.2
Radiological Work Planning
a.
Inspection Scope
The inspectors reviewed the stations processes for radiological work planning and
scheduling, and evaluated the dose projection methodologies and practices implemented
for the Q1R17 refueling outage, to verify that the technical bases for outage dose
estimates were adequate. Specifically, the inspectors reviewed radiologically significant
RWP/ALARA planning packages to verify that person-hour estimates, job history files,
lessons learned, and industry experiences were utilized in the ALARA planning process.
The inspectors also reviewed total effective dose equivalent ALARA evaluations to
assess the licensees analysis of evolutions involving potential airborne activity for the
use of respiratory protection equipment. The inspectors also attended ALARA committee
meetings and shift turnovers to further assess inter-departmental coordination and
ownership in the radiological work/ALARA planning and scheduling processes.
b.
Findings
No findings of significance were identified.
.3
Job Site Inspection and ALARA Control
a.
Inspection Scope
The inspectors reviewed jobs being performed in areas of elevated dose rates, examined
exposure estimates and work sites, and evaluated selected RWPs along with the
associated ALARA briefing packages to verify that worker radiological exposure was
minimized. Protective clothing requirements, dosimeter use including radiotelemetry
dosimetry, and electronic dosimeter alarm set points were evaluated for consistency with
RWP packages. The use of engineering controls were also reviewed to verify that
worker exposures were maintained ALARA.
24
The inspectors attended selected pre-job ALARA and work control briefings, and
observed portions of work evolutions directly and by using the licensees remote closed
circuit monitoring system in order to verify that adequate work controls were in place to
maintain worker exposures ALARA. During job site walkdowns, radworkers and
supervisors were observed to determine if low dose waiting areas were being used
appropriately, and to evaluate the effectiveness of job supervision including equipment
staging, use of shielding, availability of tools, and work crew size.
b.
Findings
No findings of significance were identified.
.4
Radiation Dose Estimates and Exposure Tracking Systems
a.
Inspection Scope
The inspectors reviewed the licensees Unit 1 outage dose goals and dose trending
records, and evaluated the licensees method for adjusting dose estimates to verify that
the licensee had implemented sound radiation protection principles and properly
identified work control problems. The inspectors also attended site ALARA committee
meetings that discussed and approved dose adjustments for radiological work activities
to assess the adequacy of management involvement in the ALARA program.
b.
Findings
No findings of significance were identified.
.5
Identification and Resolution of Problems
a.
Inspection Scope
The inspectors evaluated the effectiveness of the stations problem identification and
resolution processes to identify, characterize and prioritize problems, and to develop and
implement corrective actions. The evaluation included review of: (1) the results of a
focus area self-assessment of the ALARA Planning and Control Program performed
during 2002; (2) a Nuclear Oversight continuous assessment report along with field
observation reports of the radiation protection program (access control and ALARA
programs) that were completed in calendar years 2001 and 2002; and (3) the licensees
condition report (CR) database and individual CRs related to the access control and
ALARA programs for years 2001 and 2002.
The licensees corrective action program for radiation protection issues was evaluated to
verify that problems were appropriately prioritized and resolved in a timely manner,
commensurate with their importance based on safety and risk. This evaluation included
procedure and documentation reviews, discussions of the program with cognizant
licensee personnel, and observing management meetings in which CRs were evaluated.
25
b.
Findings
No findings of significance were identified.
Cornerstone: Public Radiation Safety
2PS2 Radioactive Material Processing and Transportation (71122.02)
.1
Walkdown of Radioactive Waste Systems
a.
Inspection Scope
The inspectors reviewed the liquid and solid radioactive waste system description in the
Final Safety Analysis Report and the most recent information regarding the types and
amounts of radioactive waste generated and disposed. The inspectors performed
walkdowns of the liquid and solid radwaste processing systems to verify that the systems
agreed with the descriptions in the Final Safety Analysis Report and the Process Control
Program, and to assess the material condition and operability of the systems. The
inspectors reviewed the current processes for transferring waste resins into shipping
containers to determine if appropriate waste stream mixing and/or sampling procedures
were utilized. The inspectors also reviewed the methodologies for waste concentration
averaging to determine if representative samples of the waste product were provided for
the purposes of waste classification in 10 CFR 61.55. During this inspection, the
licensee was not conducting waste processing.
b.
Findings
No findings of significance were identified.
.2
Waste Characterization and Classification
a.
Inspection Scope
The inspectors reviewed the licensees radiochemical sample analysis results for each of
the licensees waste streams, including dry active waste, resins, and filters. The
inspectors also reviewed the licensees use of scaling factors to quantify difficult-to-
measure radionuclides (e.g., pure alpha or beta emitting radionuclides). The reviews
were conducted to verify that the licensees program assured compliance with 10 CFR 61.55 and 10 CFR 61.56, as required by Appendix G of 10 CFR Part 20. The inspectors
also reviewed the licensees waste characterization and classification program to ensure
that the waste stream composition data accounted for changing operational parameters
and thus remained valid between the annual sample analysis updates.
b.
Findings
No findings of significance were identified.
26
.3
Shipment Preparation
a.
Inspection Scope
Since there were no radioactive materials shipped from the site during the inspection, the
inspectors reviewed the records of training provided to personnel responsible for the
conduct of radioactive waste processing and radioactive shipment preparation activities.
The review was conducted to verify that the licensees program provided training
consistent with NRC and Department of Transportation requirements.
b.
Findings
No findings of significance were identified.
.4
Shipping Records
a.
Inspection Scope
The inspectors reviewed five non-excepted package shipment documents completed
during years 2001 and 2002, to verify compliance with NRC and Department of
Transportation requirements (i.e., 10 CFR Parts 20 and 71 and 49 CFR Parts 172 and
173).
b.
Findings
No findings of significance were identified.
.5
Identification and Resolution of Problems
a.
Inspection Scope
The inspectors reviewed 2002 focus area self-assessments of the Radioactive Material
Transportation and Radioactive Waste Processing Programs to evaluate the
effectiveness of the self-assessment process to identify, characterize, and prioritize
problems. The inspectors also reviewed corrective action documentation to verify that
previous radioactive waste and radioactive materials shipping related issues were
adequately addressed. The inspectors also selectively reviewed year 2002 CRs that
addressed radioactive waste processing and radioactive materials shipping program
deficiencies to verify that the licensee had effectively implemented the corrective action
program.
b.
Findings
No findings of significance were identified.
27
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
Cornerstone: Mitigating Systems
.1
High Pressure Coolant Injection Safety System Unavailability
a.
Inspection Scope
The inspectors reviewed control room logs, condition reports, and the licensees monthly
submittals of performance indicator information to verify the high pressure coolant
injection safety system unavailability for both units from August 2001 to August 2002.
The inspectors verified that the licensee accurately reported system performance as
defined in the applicable revision of Nuclear Energy Institute Document 99-02,
Regulatory Assessment Performance Indicator Guideline.
b.
Findings
No findings of significance were identified.
Cornerstone: Barrier Integrity
.2
Reactor Coolant System Activity
a.
Inspection Scope
The inspectors reviewed the licensees reactor coolant system activity performance
indicator to verify that the information reported by the licensee was accurate. The
inspectors reviewed the licensees reactor coolant sample results for maximum dose
equivalent iodine-131 for the previous 4 quarters, and the licensees sampling and
analysis procedures. The inspectors also observed a chemistry technician obtain and
analyze a reactor coolant sample.
b.
Findings
No findings of significance were identified.
Cornerstone: Occupational Radiation Safety
.3
Occupational Exposure Control Effectiveness
a.
Inspection Scope
The inspectors reviewed the licensees determination of performance indicators for the
occupational radiation safety cornerstone to verify that the licensee accurately
determined these performance indicators had all occurrences required. The inspectors
reviewed CRs for the year 2002 and access control transactions for the year 2002.
28
During plant walkdowns the inspectors also verified the adequacy of postings and
controls for locked high radiation areas, which contributed to the Occupational Exposure
Control Effectiveness performance indicator.
b.
Findings
No findings of significance were identified.
Cornerstone: Public Radiation Safety
.4
RETS/ODCM Radiological Effluents
a.
Inspection Scope
The inspectors reviewed the licensees determination of performance indicators for the
Radiological Effluent Technical Specification/Offsite Dose Calculation Manual
Radiological Effluent Occurrences. The inspectors reviewed CRs for the year 2002 and
quarterly offsite dose calculations for radiological effluents for the previous 4 quarters.
b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
.1
1B Reactor Recirculation Pump Trips on Overcurrent Condition
a.
Inspection Scope
The inspectors assessed the circumstances surrounding the 1B reactor recirculation
pump trip by interviewing site personnel and reviewing condition reports. The inspectors
also reviewed the 1B reactor recirculation pump maintenance work history to determine if
the current pump trip was similar to previous trips.
b.
Findings
The inspectors identified one Green finding due to the failure to correct previously
identified deficiencies with the 1B reactor recirculation motor generator voltage regulator.
On December 6, 2002, the 1B reactor recirculation pump tripped on an overcurrent
condition. The licensee determined that voltage regulator instabilities caused by a lack of
adequate capacitance in the regulator circuitry caused the pump trip. The inspectors
reviewed Condition Reports 133549 and 133856 initiated on November 29 and
December 3, 2002, respectively. The inspectors determined that both of the condition
reports were written because the 1B reactor recirculation motor generator set failed to
meet the acceptance criteria specified in Procedure MA-AB-772-301 during voltage
regulator tuning activities.
29
The licensee evaluated the information in both condition reports and determined that
continued operation of the 1B reactor recirculation pump was acceptable since the
voltage regulator performance was similar to the performance experienced from
February to November 2002. The licensee planned to add additional capacitance to the
voltage regulator circuitry at a later date. The inspectors reviewed the licensees decision
to continue operating the 1B reactor recirculation pump and determined that previous
and current operating conditions had changed. During the Unit 1 refueling outage, the
licensee adjusted the voltage regulator stability and gain potentiometers on numerous
occasions. However, it did not appear that the licensee adequately considered these
subtle differences in performance prior to continuing operation.
The inspectors reviewed the 1B reactor recirculation pump maintenance work history and
discovered that the pump had tripped twice in November 2000. The licensees
investigation determined that the pump trips occurred due to equipment failures and a
lack of understanding for how the voltage regulator functioned. Corrective actions to
prevent recurrence included component replacements and voltage regulator performance
training. Based on the 1B reactor recirculation pump trip of December 6, 2002, the
inspectors determined that the licensees corrective actions to prevent recurrence were
ineffective.
The failure to adequately address the 1B reactor recirculation motor generator voltage
regulator failures was more than minor because the resulting pump trips could be
reasonably viewed as a precursor to a significant event. The inspectors determined that
this finding could be assessed using the significance determination process for the same
reason. The inspectors conducted a Phase 1 screening and determined that this finding
was of very low safety significance (Green) because it did not: (1) contribute to the
likelihood of a primary or secondary system loss of coolant accident initiator;
(2) contribute to both the likelihood of a reactor trip and the likelihood that mitigation
equipment or functions would not be available; (3) increase the likelihood of a fire or
internal/external flood; or (4) increase the frequency of core damage scenarios of
concern using the Individual Plant Examination for External Events or other plant specific
analyses (FIN 50-254/02-08-07). This issue was not subject to NRC enforcement since
the reactor recirculation pump and the motor generator voltage regulator are non-safety-
related components.
After the December 6, 2002, pump trip the licensee added approximately
500 microfarads of capacitance to the voltage regulator circuit and established an
administrative limit which prevented operating the 1B reactor recirculation pump at
greater than 92 percent speed. The licensee planned to install additional circuit
capacitance on approximately January 6, 2003.
.2
Routine Review of Identification and Resolution of Problems
a.
Inspection Scope
As discussed in previous sections of this report, the inspectors routinely reviewed issues
during baseline inspection activities and plant status reviews to verify that they were
being entered into the licensees corrective action system at an appropriate threshold,
30
that adequate attention was being given to timely corrective actions, and that adverse
trends were identified and addressed. Issues entered into the licensees corrective
action system as a result of inspectors observations are generally denoted within the
body of the report. Specific issues related to routine problem identification and resolution
were discussed in Sections 1R20.4, 4OA2.1, and 4OA3.2 of this report.
b.
Findings
No findings of significance were identified.
4OA3 Event Follow-up (71153)
.1
(Closed) Licensee Event Report 50-265/02-004: Inadequate Separation in Both Trip
Systems of the Scram Discharge Instrument Volume Input to the Reactor Protection
System.
On August 2, 2002, the licensee determined that an engineering change (EC 24572),
implemented in March 2002 resulted in the failure to maintain electrical separation
between the safety-related reactor protection system cabling and the non-safety-related
plant computer. Upon discovery the licensee entered Technical Specification 3.3.1.1,
Condition B, which allowed 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to place the reactor protection system in a tripped
condition. The licensee installed a temporary modification within the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> which
disabled the scram discharge volume input to the plant computer.
The licensee failed to identify this electrical separation issue earlier due to a lack of rigor
during the modification review process. The inspectors determined that this issue was
minor since one channel in each reactor protection trip system remained operable. In the
event that there had been an actual scram discharge volume high level condition,
concurrent with the plant computer cabling and the reactor protection system wiring
shorting together, the scram function would still have been initiated.
.2
(Closed) Licensee Event Report 50-265/02-005: Failure of Low Pressure Coolant
Injection Logic Test due to Detached Wire.
During logic testing on the 2B residual heat removal subsystem on October 7, 2002,
operations personnel were unable to complete a step in QCOS 1000-44, Unit 2 B Loop
Low Pressure Coolant Injection and Containment Cooling Modes of Residual Heat
Removal Non-Outage Logic Test. Troubleshooting identified an unlanded wire that
should have been connected to fuse holder FF-F11 within the residual heat removal logic
circuitry. The licensee determined that the failure of the wire to be connected to the fuse
holder resulted in the 2B residual heat removal subsystem being unable to automatically
start in response to an emergency core cooling system initiation signal. The licensee
also found that if the 2B residual heat removal subsystem was operating in torus spray or
torus cooling certain valves would not have automatically closed upon the receipt of an
emergency core cooling system initiation signal. As a result, low pressure injection from
the 2A residual heat removal subsystem would have been diverted from the reactor
vessel to the torus through the open torus cooling and/or torus spray valves until the
operators manually closed the valves.
31
The inspectors determined that human performance and problem identification and
resolution deficiencies contributed to the failure to identify and correct the residual heat
removal wiring issue. On February 18, 2002, maintenance personnel performed
activities inside the electrical panel containing fuse block FF-F11. The maintenance work
conducted required fuse block FF-F11 to be moved; no wires were de-terminated from
the fuse block. Following the electrical panel maintenance, personnel re-installed fuse
block FF-F11 but did not visually or physically verify the integrity of any wiring
connections. Testing following the maintenance demonstrated that the wiring connected
to fuse block FF-F11 was in contact with the fuse block. However, the licensee believes
the wiring was loose. Instrument maintenance personnel conducted several
surveillances between March 18 and October 7, 2002, with unexpected results. Although
actions were taken to document the unexpected results, the rigor in evaluating these
results was less than adequate since equipment operability was not addressed.
On March 1, 2002, operations personnel completed QCOS 6600-48, Unit 2 Division 2
Emergency Core Cooling System Simulated Automatic Actuation and Diesel Generator
Auto-Start Surveillance. The test completion demonstrated that the wires associated
with fuse block FF-F11 remained in contact with the fuse block. Approximately
2.5 weeks later, instrument maintenance personnel conducted QCIS 1000-13, High
Drywell Pressure Core Spray, Low Pressure Coolant Injection, and Emergency Diesel
Generator Calibration and Functional Test. During this test the instrument technicians
noticed that the residual heat removal lights for high drywell pressure did not illuminate
as expected. One light flickered and extinguished; the other light never illuminated.
Since the light illumination was not part of the QCIS 1000-13 acceptance criteria, the
instrument technicians noted their observation and generated Work Order 421277 to
investigate the light failure. Troubleshooting by the fix-it-now team determined that the
light failures were not caused by burnt out bulbs. No other actions were taken to explain
the significance or cause of the light failure. Instead Work Order 421277 was
re-scheduled for completion during the May 2002 residual heat removal work week
window. Prior to May 2002, Work Order 421277 was re-classified as outage work for
unknown reasons. The inspectors noted that the next Unit 2 refueling outage was not
scheduled until 2004. During performances of QCIS 1000-13 on June 13 and
September 6, 2002, the instrument technicians continued to document the failure of the
residual heat removal lights for high drywell pressure to illuminate. No actions were
taken following the subsequent performances of QCIS 1000-13 due to the licensees
belief that the lights were for indication only.
The inspectors determined that the failure to adequately address the impact of the
extinguished lights were more than minor because it: (1) involved the configuration
control, equipment performance, and human performance attributes of the mitigating
systems cornerstone; and (2) affected the cornerstone objective of ensuring the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences.
The inspectors also determined that this finding should be evaluated using the
Significance Determination Process described in Inspection Manual Chapter 0609,
Significance Determination Process, because the finding was associated with the
availability of a mitigating system. The inspectors conducted a Phase 1 screening and
determined that a Phase 2 evaluation was required since the disconnected wire resulted
32
in an actual loss of safety function of a single train for greater than the Technical
Specification Allowed Outage Time. This finding also resulted in an actual loss of safety
function of the residual heat removal system during times when the 2B system was
operating in the torus cooling or torus spray modes.
The inspectors used the risk-informed inspection notebook for Quad Cities Nuclear
Power Station, Units 1 and 2, Revision 1, dated May 2, 2002, to complete the Phase 2
evaluation. The inspectors determined that the exposure time was greater than 30 days
which increased the initiating event likelihood for all initiating events by two orders of
magnitude. For each worksheet the inspectors assumed that all mitigating capability was
available except for both residual heat removal subsystems. The inspectors allowed
credit for recovery since the residual heat removal system could be aligned for low
pressure injection through manual operator actions. This resulted in 11 core damage
sequences between 9 and 14 points. The most dominant core damage sequences
involved: (1) the loss of the power conversion system with high pressure injection
equipment and the core spray system available; (2) a large break loss of coolant accident
with the core spray system available; and (3) a loss of offsite power with the high
pressure injection systems and the core spray system available. The inspectors
concluded that the final significance determination process result for this finding was
9 points; therefore, this finding was considered to be of very low risk significance
(Green).
Technical Specification 3.5.1, Emergency Core Cooling System - Operating, requires
that each emergency core cooling system injection and/or spray subsystem be operable
in Modes 1, 2, and 3. Technical Specification 3.5.1, Condition B, allows one residual
heat removal subsystem to be inoperable for up to 7 days. Condition C of the same
Technical Specification allows both residual heat removal subsystems to be inoperable
for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The inspectors determined that as of March 18, 2002, the 2B residual
heat removal subsystem, an emergency core cooling system, was inoperable. In
addition, both residual heat removal subsystems were inoperable at various times
between March 18 and October 7, 2002. This determination was based upon the fact
that as of March 18 the licensee was no longer able to ensure that the wire was
adequately secured to fuse block FF-F11. The failure to have both residual heat removal
subsystems operable while operating in Modes 1, 2, and 3 was considered a Non-Cited
Violation of Technical Specification 3.5.1 in accordance with Section VI.A.1 of the NRCs
Enforcement Policy (NCV 50-265/02-08-08). This issue was entered into the licensees
corrective action program as Condition Report 126235.
.4
Unit 1 in Single Loop Operation Due to 1B Reactor Recirculation Pump Trip
On December 6, 2002, the inspectors reviewed the circumstances surrounding the 1B
reactor recirculation pump trip. The inspectors reviewed the timeliness and adequacy of
operator actions during the transient condition. The inspectors determined that the
operators reacted appropriately and followed procedural requirements during the
transient condition. The inspectors also determined through observation that the
operators appropriately implemented procedures to allow the unit to operate in single
33
loop operations during the troubleshooting and reactor recirculation pump restoration
activities. Further information regarding the incident is described in Section 4OA2 of this
report.
4OA4 Cross-Cutting Findings
.1
Human Performance Related Findings
Findings described in Sections 1R20.1, 1R20.2, 1R20.3, and 4OA3.2 of this report had
one or more human performance deficiencies which caused the event to occur. An
individual failed to use self-check techniques when identifying the proper plant air supply
for an air powered vacuum. This error resulted in two separate instrument air transients
on October 24 and 25, 2002 (see Section 1R20.1).
A communications weakness between operations, maintenance and contractor personnel
resulted in a large amount of water being expelled from a stator water heat exchanger
during maintenance. The water migrated to the room below and resulted in the Unit 1
emergency diesel generator being declared inoperable (see Section 1R20.2).
Failure to follow procedures and untimely control room panel monitoring led to the
unexpected isolation of the reactor water cleanup system while the system was being
used to remove decay heat during the Unit 1 refueling outage (see Section 1R20.3).
Lastly, the failure to verify the physical integrity of wiring connections following
maintenance activities led to a condition which resulted in the 2B residual heat removal
system being inoperable for more than 6 months (see Section 4OA3.2).
.2
Problem Identification and Resolution Related Findings
The licensee did not initiate condition reports following the inspectors identification of
multiple scaffolding erection deficiencies (see Section 1R20.4). As a result, additional
scaffolding deficiencies were identified by other plant personnel. Later in the inspection
period, the licensee initiated a condition report encompassing all of the inspector
identified scaffolding issues. Once this action was taken, the licensee began conducting
an evaluation to determine whether a common cause had contributed to some or all of
the identified deficiencies.
Weaknesses in problem evaluation resulted in the failure to correct deficiencies with the
1B reactor recirculation voltage regulator (see Section 4OA2.1). On November 29 and
December 3, 2002, the licensee initiated two condition reports due to the 1B reactor
recirculation pump voltage regulator failing to meet proceduralized acceptance criteria.
During the evaluation of these condition reports, the licensee did not fully consider
changes made to the voltage regulator during the outage and power ascension. These
actions resulted in Unit 1 being at an increased risk for a plant transient and a
subsequent reactor recirculation pump trip on December 6, 2002.
Deficiencies in problem evaluation and prioritization also led to the failure to recognize
that the 2B residual heat removal system was inoperable (see Section 4OA3.2). The
inspectors determined that licensee personnel had at least three prior opportunities to
34
identify this condition prior to discovery of the condition on October 7, 2002. These
opportunities were not acted upon due to the licensees belief that an extinguished light
was for indication only rather than a sign of equipment malfunction.
4OA5 Other Activities
.1
Completion of Appendix A to TI 2515/148, Revision 1
The inspectors completed the pre-inspection audit for interim compensatory measures at
nuclear power plants, dated September 13, 2002.
.2
a.
Inspection Scope
The inspectors observed control room activities associated with the Unit 1 power uprate
including power ascension testing and surveillance testing. The inspectors also reviewed
daily licensee power uprate observations and evaluations to ensure deficiencies were
adequately evaluated. The inspectors performed tours of the turbine building and reactor
building to assess plant conditions as power ascension activities progressed. The
inspectors reviewed plant modification plans and post-modification testing.
b.
Findings
No findings of significance were identified.
4OA6 Meetings
.1
Exit Meeting
The inspectors presented the inspection results to Mr. T. Tulon and other members of
licensee management at the conclusion of the inspection on December 31, 2002. The
inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
.2
Interim Exit Meetings
Interim exits were conducted for:
Temporary Instruction 2515/148, Appendix A with Mr. B. Swenson on
October 25, 2002.
Access Control, ALARA Planning and Control, and Radwaste and Transportation
with Mr. T. Tulon on November 15, 2002.
Inservice Inspection with Mr. T. Tulon on November 21, 2002.
35
4OA7 Licensee-Identified Violations
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 Manual, NUREG-1600, for being dispositioned as Non-Cited Violations.
Cornerstone: Mitigating Systems
Technical Specification Surveillance Requirement 3.8.4.7 requires that the licensee verify
that battery capacity is adequate to supply, and maintain in an operable status, the
required emergency loads for the design duty cycle every 24 months. As described in
Condition Report 124350, on September 24, 2002, the licensee had not included
charging spring motor loads for certain General Electric 480 Volt breakers as part of the
design duty cycle during previous battery testing. As a result, the license had not
adequately performed the surveillance testing required by Technical Specification
Surveillance Requirement 3.8.4.7.
The licensee entered Technical Specification Surveillance Requirement 3.0.3 in response
to the missed surveillance test. This surveillance requirement allowed the licensee to
delay entry into Technical Specification 3.8.7 due to the discovery of missed
surveillances as long as the a risk evaluation was performed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and the
missed surveillance tests were completed within the Technical Specification specified
frequency (in this case 24 months). The inspectors reviewed the licensees risk
assessment and determined that the risk to the plant from the missed surveillances was
very low since calculations showed that adequate battery capacity was available to
supply all required loads. Subsequent testing of the Unit 1 and 2 batteries also
demonstrated that adequate capacity was available to supply the required loads.
36
KEY POINTS OF CONTACT
Licensee
T. Tulon, Site Vice President
B. Swenson, Plant Manager
D. Barker, Radiation Protection Manager
W. Beck, Regulatory Assurance Manager
G. Boerschig, Work Control Manager
R. Gideon, Engineering Manager
K. Hungerford, Wackenhut Project Manager
A. Javorik, Maintenance Manager
M. Karney, Midwest ROG Security Manager
K. Leech, Security Manager
K. Moser, Chemistry/Environ/Radwaste Manager
M. Perito, Operations Manager
M. Snow, Nuclear Oversight Manager
Nuclear Regulatory Commission
M. Ring, Chief, Reactor Projects Branch 1
C. Lyon, Project Manager
K. Ohr, Radiation Protection Supervisor
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-254/02-08-01
Inadequate Design Leads to Delay in Discovering Safe Shutdown
50-265/02-08-01
Makeup Pump was Inoperable due to Strainer Clogging
50-254/02-08-02
Resolution of American Society of Mechanical Engineers
50-265/02-08-02
Requirements
50-254/02-08-03
Inadequate Procedure and Self Checking Results in Connecting
50-265/02-08-03
Air Powered Vacuum to Instrument Air System and two Air
50-265/02-08-04
Inadequate Procedure and Communication Weaknesses Leads to
Emergency Diesel Generator Inoperability
50-254/02-08-05
Failure to Follow Procedure and Weak Control Board Monitoring
Leads to Inadvertent Reactor Water Cleanup Isolation
50-254/02-08-06
Multiple Examples of Scaffolding in Contact with Safety-Related
Equipment
37
50-254/02-08-07
Weaknesses in Problem Identification and Resolution Leads to 1B
Reactor Recirculation Pump Trip
50-265/02-08-08
Human Performance and Problem Identification and Resolution
Results in Failure to Discover Impact of Loose Lead on Residual
Heat Removal Inoperability
Closed
50-254/02-08-01
Inadequate Design Leads to Delay in Discovering Safe Shutdown
50-265/02-08-01
Makeup Pump was Inoperable due to Strainer Clogging
50-254/02-08-03
Inadequate Procedure and Self Checking Results in Connecting
50-265/02-08-03
Air Powered Vacuum to Instrument Air System and two Air
50-265/02-08-04
Inadequate Procedure and Communication Weaknesses Leads to
Emergency Diesel Generator Inoperability
50-254/02-08-05
Failure to Follow Procedure and Weak Control Board Monitoring
Leads to Inadvertent Reactor Water Cleanup Isolation
50-254/02-08-06
Multiple Examples of Scaffolding in Contact with Safety-Related
Equipment
50-254/02-08-07
Weaknesses in Problem Identification and Resolution Leads to 1B
Reactor Recirculation Pump Trip
50-265/02-08-08
Human Performance and Problem Identification and Resolution
Results in Failure to Discover Impact of Loose Lead on Residual
Heat Removal Inoperability
50-265/02-004
LER
Inadequate Separation in both Trip Systems of the Scram
Discharge Instrument Volume Input to the Reactor Protection
System
50-265/02-005
LER
Failure of Low Pressure Coolant Injection Logic Test due to
Detached Wire
Discussed
None
38
LIST OF ACRONYMS USED
As-Low-As-Is-Reasonably-Achievable
Agencywide Documents Access and Management System
CFR
Code of Federal Regulations
CR
Condition Report
Finding
IMC
Inspection Manual Chapter
Non-Cited Violation
Publically Available Records System
Radiation Work Permit
Significance Determination Process
39
LIST OF DOCUMENTS REVIEWED
1R01
Adverse Weather
QCOP 0010-01; Winterizing Checklist; Revision 17
QCOP 0010-02; Required Cold Weather Routines; Revision 12
Quad Cities Winter Readiness Operating Experience
IE Bulletin 79-24; Frozen Lines; dated September 27, 1979
Licensees Response to IE Bulletin 79-24; dated October 30, 1979
List of Open Work Requests on the Ice Melt Valve and Heat Tracing System
Winter Readiness 2002-2003 Open Items List
OP-AA-108-109, Attachment 3; System Engineering System Readiness Review; various
dates
Condition Report 79845; Clean Demineralizer Suction Piping Installed At Risk; dated
October 23, 2001
Condition Report 80242; Unit 2 Traveling Screen High Differential Pressure Due to
Shear Pin Failure; dated October 25, 2001
Condition Report 81415; Cold Weather Preparations; dated November 2, 2001
Condition Report 82901; Ice Melt Valve - Limitorque Failure, Damage to Worm/Worm
Gear; dated November 14, 2001
Condition Report 93918; Unit 1 Startup Delayed 24 Hours Due to CIV #1 Stuck Closed;
dated February 4, 2002
Condition Report 98562; High Traveling Screen Differential Pressure Alarm on Unit 2;
dated March 10, 2002
Condition Report 112590; U-1 and 2 HRSS Sample Heat Trace Circuits Turned Off;
dated June 20, 2002
Condition Report 127693; Corrective Action Work Request Canceled; dated October 16,
2002
Condition Report 127842; Need to Inspect Duct for Foreign Material; dated October 17,
2002
40
Condition Report 127679, Safe Shutdown Makeup Pump Room Observed Warmer Than
Usual; dated October 16, 2002
Apparent Cause Evaluation for Condition Report 127679; dated October 25, 2002
QCMPM 2900-01; Unit 1/2 Safe Shutdown Pump Room Air Handling Unit Cooling Service
Water Strainer Preventive Maintenance; Revision 4; dated August 30 - October 31, 2002
Exelon Quality Assurance Topical Report; Revision 69
1R05 Fire Protection
Quad Cities Pre-Plan TB-69; Unit 1 Turbine Building, Elevation 595'-0" Hallway Fire
Zone 8.2.6.A
Quad Cities Pre-Plan TB-66; Unit 1 Turbine Building, Elevation 572'-6" CRD Pumps Fire
Zone 8.2.3.A
Quad Cities Pre-Plan TB-68; Unit 1 Turbine Building, Elevation 595'-0" Low Pressure
Heater Bay Fire Zone 8.2.6.B
Quad Cities Pre-Plan RB-24; Unit 1/2 Reactor Building, Elevation 690'-6" Refuel Floor
Quad Cities Pre-Plan RB-16; Unit 2 reactor Building, Elevation 554'-0" NW Corner
Room - 2A Core Spray Fire Zone 11.3.3
Quad Cities Pre-Plan RB-17; Unit 2 Reactor Building, Elevation 554'-0" SE Corner
Room - 2B RHR Room Fire Zone 11.3.2,
Quad Cities Pre-Plan RB-18; Unit 2 Reactor Building, Elevation 554'-0" NE Corner
Room - 2A RHR Room Fire Zone 11.3.4,
Quad Cities Station Units 1 and 2 Fire Hazards Analysis; dated August 2001
OP-AA-201-001; Fire Marshall Tours; Revision 1
OP-AA-201-004; Fire Prevention for Hot Work; Revision 5
OP-AA-201-008; Pre-Fire Plans; Revision 1
OP-AA-201-009; Control of Transient Combustibles; Revision 2
1R08 Inservice Inspection
ER-AA-335-005; Radiographic Examination; Revision 0
PT-EXLN-104V0; Procedure for Liquid Penetrant Examination Color Contrast (Visible)
Solvent Removable; dated November 7, 2001
41
GE-UT-311; Procedure for Manual Ultrasonic Examination of Nozzle Inner Radii and
Bore; dated January 9, 2001
GE-PDI-UT-1; PDI Generic Procedure for the Ultrasonic Examination of Ferritic Pipe
Welds; dated October 24, 2002
GE-PDI-UT-2; PDI Generic Procedure for the Ultrasonic Examination of Austenitic Pipe
Welds; dated October 24, 2002
ISI Program Plan, Third 10-Year Inspection Interval, Quad Cities Station, Units 1 & 2;
dated May 22, 2001
Quad Cities Generating Station Unit 2, Post Outage (90 Day) Summary Report,
Refueling Outage Q2R16; dated June 3, 2002
Action Report 00132057; NRCs Position Regarding CRD Housing Weld Inspections
Action Report 00113995; Dresden Missed Inspections of CRD Housing Welds
(Condition Report 113590)
Radiographic Examination Report RT-005; dated November 20, 2002
1R11 Licensed Operator Requalification
Scenario 00-28; Torus Narrow Range Instrument Failure, Loss of Coolant Accident
Inside Containment, and an Anticipated Transient Without Scram; Revision 10
QCOA 0201-01; Increasing Drywell Pressure; Revision 15
QCOP 0300-28; Alternate Rod Insertion; Revision 18
QCOA 0400-01; Reactivity Addition; Revision 13
QCOA 3200-01; Reactor Feed Pump Auto Trip; Revision 11
QGA 100; Reactor Pressure Vessel Control; Revision 7
QGA 101; Reactor Pressure Vessel Control (Anticipated Transient Without Scram);
Revision 10
QGA 200; Primary Containment Control; Revision 8
1R13 Maintenance Risk Assessment and Emergent Work
OU-AA-103; Shutdown Safety Management Program; Revision 1
Work Week Safety Profile; Week of December 9, 2002
OU-QC-104; Daily Risk Factor Chart, Attachment 1; Revision 1
42
WC-AA-104; Review and Screening for Production Risk; Revision 4
Online Work Schedules; Week of December 9, 2002
1R14 Non-Routine Evolutions
QCGP 3-1; Reactor Power Operations; Revision 29
QCGP 3-2; Control of Planned Reactor Power Changes; Revision 13
QCGP 4-1; Control Rod Movements and Control Rod Sequences; Revision 22
1R15 Operability Evaluations
Condition Report 132057; NRCs Position Regarding Control Rod Drive Housing Weld
Inspections; dated November 17, 2002
Condition Report 124350; Certain General Electric 480 Volt Breakers not Properly
Modeled in ELMS-DC Database; dated September 24, 2002
Condition Report 131936, Unit 2 Main Steam Isolation Valves 2-0203-2B and 2-0203-2C
Contain Belleville Springs in the Low Liner Assembly Which are Suspect for Potential
Failure; dated November 20, 2002
1R16 Operator Workarounds
OP-AA-101-103; Operator Work-Around Program; Revision 0
List of Open Operator Workarounds and Operator Challenges; dated October 10, 2002
Condition Report 110692; Work on Valve 1-2001-794 Rescheduled due to Welding
Resources and Pipe Interference; dated June 5, 2002
OP-AA-108-102; Equipment Status Tag Log; dated October 11, 2002
Unit 1 Nuclear Station Operator Turnover Checklist; dated October 11, 2002
Unit 2 Nuclear Station Operator Turnover Checklist; dated October 11, 2002
Temporary Configuration Change Report; dated October 11, 2002
Operability Determinations with Open Compensatory Actions or Corrective Actions Log;
dated October 11, 2002
Operator Burden Review; dated July 2002
Operator Burden Review; dated October 2002
43
1R17 Permanent Plant Modifications
Engineering Change Package 24165; Trip Condensate/Booster Pump 1D on Loss of
Coolant Accident and With All four Condensate/Booster Pumps 1A, 1B, 1C, and 1D
Running; dated May 9, 2001
Engineering Change Package 24169; Main Steam Flow High Setpoint Change and
Differential Pressure Switch Replacement; dated January 16, 2001
Engineering Change Package 24420; Reactor Feed Pump and Motor Generator Set
Breaker Time Delay Modification; dated June 5, 2001
Engineering Change Package 337693; Isophase Bus Duct Cooling System Upgrade to
Support Extended Power Uprate Operation
Calculation QDC-3000-I-0986; Main Steam Line High Flow Differential Pressure Switch
Setpoint Error Analysis; Revision 0
Engineering Change 24432; Extended Power Uprate Project Main Steam Pipe Support
Project Main Steam Pipe Support and Drywell Steel Modifications; Revision 3
1R19 Post Maintenance Testing
QCOS 1100-07; SBLC Pump Flow Rate Test; Unit 1, Revision 22
QOM 1-1100-01; U1 Standby Liquid Control Valve Check List; Revision 9
QCOS 2300-28; HPCI Turning Gear Logic Functional Test; Revision 8
Work Order 416235-01; Replace Agastat Time Delay Relay 1-2300-121 in Panel 901-39;
dated October 22, 2002
Engineering Change Request 51124; Obtain Time Delay Criteria for 2330-121 Relay;
dated September 16, 1998
Drawing 4E-1526; Schematic Control Diagram HPCI System Block Diagram 8 Control
Switch Development; Revision T
Drawing 4E-1527; Schematic Diagram High Pressure Coolant Injection System Sensors
and Auxiliary Relays; Sheet 1; Revision R
Drawing 4E-1527; Schematic Diagram High Pressure Coolant Injection System Sensors
and Auxiliary Relays; Sheet 2; Revision H
Drawing 4E-1527; Schematic Diagram High Pressure Coolant Injection System Sensors
and Auxiliary Relays; Sheet 3; Revision M
Drawing 4E-1532; Schematic Diagram High Pressure Coolant Injection System Turbine
Auxiliary Pumps; Revision AA
44
1R20 Refueling and Outage
Condition Report 128977; Moisture Separator Decon Work Used IA Instead of SA; dated
October 25, 2002
Work Order 369947; Moisture Separator Decontamination Work
Units 1 and 2 Control Room Logs; dated October 24-25, 2002
Condition Report 130694, Stator Water Heat Exchanger Spill; dated November 7, 2002
Out of Service Tagout 00011947
Work Order 99183182, Task 01; Replace Tube Bundle Assembly in the 1-7401-A Stator
Cooling Water Heat Exchanger
Condition Report 133054; Unit 1 RWCU Isolation; dated November 24, 2002
Unit 1 Control Room Logs; dated November 24, 2002
QCOP 1200-15, Operation of Decay Heat Removal Mode of RWCU System; Revision 13
QCOP 1200-13, RWCU System High Temperature Isolation Setpoint Adjustment;
Revision 3
Unit 1 Main Condenser Clearance Order 00011583
Unit 1 High Pressure Coolant Injection Clearance Order 00012820
Procedure OU-AA-103; Shutdown Safety Management Program; Revision 1
Procedure OU-QC-104; Shutdown Safety Management Program Quad Cities Annex;
Revision 2
QCOA 1000-02; Loss of Shutdown Cooling; Revision 12
QCOS 1000-24; Shutdown Cooling Outage Report; Revision 5
QCOP 1000-38; Alternate Shutdown Cooling; Revision 3
QCOA 1000-03; RHR Pump Trip; Revision 6
QCOP 1000-17; Shutdown Cooling, Reactor Temperature Trending; Revision 11
QCOP 1000-05; Shutdown Cooling Operation; Revision 30
QCOP 1200-15; Operation of Decay Heat Removal Mode of Reactor Water Cleanup
System; Revision 13
45
QCGP 1-1; Normal Unit Startup; Revision 44
QCGP 3-1; Reactor Power Operations; Revision 29
OP-AA-108-108; Unit Restart Review; Revision 0
Shutdown Safety Risk Profile Worksheets; dated November 5 - November 25, 2002
Condition Report 131936; Missing Belleville Washer in 1-0203-2C Main Steam Isolation
Valve; dated November 5, 2002
Condition Report 130946; Parts Found in Turbine Stop Valve Strainer; dated
November 8, 2002
Technical Evaluation of Degraded Main Steam Isolation Valve Belleville Springs
Identified During Q1R17
Indication Notification Report Q1R17-02-01; Steam Dryer; dated November 8, 2002
Condition Report 130921; Deformed Steam Dryer Exhaust Skirt and Cracked Tie Bar
Weld; dated November 8, 2002
Engineering Change 24495; Power Uprate - Modify Reactor Vessel Steam Dryer to
Reduce Moisture Carryover; dated November 12, 2002
Letter from Mark O. Lenz and James D. Adam, General Electric to Bruce Phares, Exelon
Nuclear; Re: Quad Cities Unit 1, Jet Pump 16 Slip Joint; dated November 15, 2002
1R22 Surveillance Testing
QOS 6500-03; Undervoltage Functional Test 4 KV Bus 14-1; Revision 21
QCOS 6600-49; Division 1 ECCS Automatic Actuation Test; Revision 5
QCOS 6600-50; Division 1 ECCS Automatic Actuation Test; Revision 6
Technical Specifications
Updated Final Safety Analysis Report
1R23 Temporary Plant Modifications
Engineering Change Request 357803; dated 11/11/02
Engineering Change 339810; Revision 1
Temporary Interim Change Procedure 576; Drywell Equipment Drain Sump Temporary
Pump Installation; dated 11/13/02
46
CC-AA-112; Temporary Configuration Changes; Revision 5
Engineering Change 339708; Installation of Temporary Bladders to Maintain Secondary
Containment; dated November 7, 2002
10 CFR 50.59 Screening QC-S-2002-0376; Installation of Temporary Bladders to
Maintain Secondary Containment; dated November 7, 2002
QCMM 0203-03; Installation, Maintenance, and Removal of Line Plugs in the Main Steam
Line to Provide Secondary Containment with the MSIV Room Part of the Turbine
Building; Revision 0
Updated Final Safety Analysis Report
Technical Specifications
2OS1 Access Control
2OS2 ALARA Planning and Controls
10001409; RWP/ALARA Plan/Work In Progress Review: U1 Moisture Separators:
Chem Decon; Revision 2
10001341; RWP/ALARA Plan: U1 Main Turbine Overhaul/PM; Revision 2
10001253; RWP/ALARA Plan: ERV/SRV/Target Rock Valves: Remove/Replace;
Revision 3
10001289; RWP/ALARA Plan: Overhaul B, C, D Inboard MSIVs; Revision 1
10001909; RWP/ALARA Plan: U1 Steam Dryer Cover Plate Mod: Diving Activities:
Diving Activities; Revision 1
10001362; RWP/ALARA Plan: U1 Reactor Steam Dryer: Mod To Reduce Carryover
(Divers); Revision 0
10001341; RWP-TEDE ALARA Evaluations; Revisions 1 and 2
Trend Charts, Unit 1 Soluble/Insoluble Cobalts 58/60; from June 1998 through
November 2002
Exposure Reduction Charter; Revision 2
Reactor Coolant I-131 Equivalent from May 15, 2002 through October 2, 2002
Reactor Coolant Neptunium 239 from May 15, 2002 through September 4, 2002
Unit 1 Dose Equivalent Iodine from November 5, 2000 through November 5, 2002
47
RP-AA-441; Evaluation and Selection Process For Radiological Respirator Use;
Revision 2
QCCP 0200-01; Reactor Water Iodine Analysis; Revision 11
Performance Indicator Data (Effluents) from October 2001 through September 2002
Performance Indicator Data (Occupational) from October 2001 through September 2002
Dose Equivalent Iodines U1/U2 from October 2001 through September 2002
Drywell Survey Map 579 Elevation; dated November 5, 2002
Drywell Survey Map 592 Elevation; dated November 8, 2002 Drywell Survey Map 614
Elevation; dated November 7, 2002
Drywell Survey Map 640 Elevation; dated November 9, 2002
Drywell Survey Map 652 Elevation; dated November 9, 2002
105357; Nuclear Oversight Identified Deficiencies in RP Documentation Reviews In First
Quarter Assessment; dated April 25, 2002
107216; Contamination Found in Clean Area In U2 5 Rack; dated May 15, 2002
104218; 2B RHR Room Cooler Work Scope Not Properly Communicated To RP; dated
April 16, 2002
103141; Erroneous ED Record Without Proper Follow up Causes RWP Lock; dated
April 10, 2002
127222; Elevated Dose Rates in Rad Waste Basement; dated October 11, 2002
127441; Poor Rad Worker Practices Identified; dated October 17, 2002
128774; High radiation Area Identified in Radwaste Max Recycle; dated October 4, 2002
Q1R17 Dose Estimates; dated November 7, 2002
Q1R17 Outage Dose Estimate Review; dated November 12, 2002
2PS2 Radioactive Material Processing and Transportation
Focus Area Self-Assessment Report, Radioactive Material Transportation; dated
July 30, 2002
Focus Area Self-Assessment Report Radiation, Radwaste; dated May 16, 2002
RW-AA-100; Process Control Program for Radioactive Wastes; Revision 2
48
QCRP 5620-0610; CFR 61 Waste Stream Sampling and Analysis; Revision 2
RP-AA-600; Radioactive Material/Waste Shipments; Revision 5
Shipment No QC-01-307 Type B, Y-III, Irradiated Hardware; dated April 20, 2001
Shipment No QC-01-311 Type B, Y-III, Irradiated Hardware; dated May 4, 2001
Shipment No QC-02-328 Type A, Y-III, Control Rod Drives; dated February 20, 2002
Shipment No QC-02-001 LSA II, Y-III, Dewatered Resin; dated June 4, 2002
Shipment No QC-02-324 SCO I, Safety Valves; dated February 17, 2002
AR 00076148Q2001-02884; RAM Shipping Personnel Not Trained IAW IATA; dated
September 17, 2001
AR 00090308; Improper Unloading of a Radioactive Material Shipment; dated
January 14, 2002
AR 00100601; HIC Dose Rate Higher Than Normal; dated March 22, 2002
AR 00123322; Water in Radioactive Shipment; dated September 18, 2002
4OA1 Performance Indicator Verification
Nuclear Energy Institute Document 99-02; Regulatory Assessment Performance
Indicator Guideline; Revision 2
LS-AA-2050; Monthly Performance Indicator Data Elements for Safety System
Unavailability-High Pressure Injection (BWR) or High Pressure Safety Injection (PWR);
Revision 2; dated August 2001-August 2002
4OA3 Event Followup
Updated Safety Analysis Report
Technical Specifications
Condition Report 126235; While Performing QCOS 1000-44 2B RHR Logic Test, Could
Not Complete Step H.4.1.1; dated October 7, 2002
Prompt Investigation for Condition Report 126235; Disconnected Lead Found During U2
LPCI Logic Test; dated October 7, 2002
Management Review Committee Update; RHR Logic Test Failure due to Detached Lead;
dated October 29, 2002
49
QCOP 0202-21, Unit 1 Reactor Recirculation System Shutdown of One Pump,
Revision 4
QCOP 0202-07, Reactor Recirculation Single Loop Operation Determination of Total
Core Flow, Revision 12
QCOP 0202-02, Reactor Recirculation System Startup, Revision 24
QCOP 0202-13, Reactor Recirculation Flow Control Line Determination, Revision 7
TIC-510, Quad Cities Unit 1 EPU Power Ascension Test Procedure
Engineering Change 24495; Power Uprate - Modify Reactor Vessel Steam Dryer to
Reduce Moisture Carryover; dated November 12, 2002
Engineering Change 337693; Isophase Bus Duct Cooling Modification; dated
October 4, 2002
Work Order 453748; Remove and replace Modified Standby Liquid Control Relief Valves
for EPU
EC 24165; Trip Condensate/Booster Pump 1D on Loss of Coolant Accident and With All
Four Condensate/Booster Pumps 1A, 1B, 1C, and 1D Running; dated May 9, 2001
EC 24169; Main Steam Flow High Setpoint Change and Differential Pressure Switch
Replacement; dated January 16, 2001
EC 24420; Reactor Feed Pump and Motor Generator Set Breaker Time Delay
Modification; dated June 5, 2001
Calculation QDC-3000-I-0986; Main Steam Line High Flow Differential Pressure Switch
Setpoint Error Analysis; Revision 0
EC 24432; Extended Power Uprate Project Main Steam Pipe Support Project Main
Steam Pipe Support and Drywell Steel Modifications; Revision 3
4OA7 Licensee-Identified Violations
Condition Report 124350; Certain General Electric 480 Volt Breakers not Properly
Modeled in ELMS-DC Database; dated September 24, 2002
Risk Management Documentation Number SA-1114; Technical Specification Surveillance
Requirement 3.0.3 Risk Evaluation of Revised 125 V Direct Current Profile; dated
October 4, 2002