ML052130286
| ML052130286 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 07/29/2005 |
| From: | Ring M NRC/RGN-III |
| To: | Crane C Exelon Generation Co |
| References | |
| FOIA/PA-2010-0209 IR-05-008 | |
| Download: ML052130286 (55) | |
See also: IR 05000237/2005008
Text
July 29, 2005
Mr. Christopher M. Crane
President and Chief Nuclear Officer
Exelon Nuclear
Exelon Generation Company, LLC
4300 Winfield Road
Warrenville, IL 60555
SUBJECT: DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3
NRC INTEGRATED INSPECTION REPORT 05000237/2005008;
Dear Mr. Crane:
On June 30, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Dresden Nuclear Power Station, Units 2 and 3. The enclosed report presents the
inspection findings which were discussed with Mr. D. Bost and other members of your staff on
July 12, 2005.
The inspection examined activities conducted under your license as they relate to safety and to
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, four NRC identified findings of very low safety
significance were identified. Two of these findings involved a violation 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 any Non-Cited Violation, you should provide a response within 30 days of the
date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001; with copies to
the Regional Administrator, Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352;
the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C.
20555-0001; and the NRC Resident Inspector at the Dresden Nuclear Power Station.
C. Crane -2-
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) component of NRC's
document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Mark A. Ring, Chief
Branch 1
Division of Reactor Projects
Docket Nos. 50-237; 50-249
Enclosure: Inspection Report 05000237/2005008; 05000249/2005008
w/Attachment: Supplemental Information
cc w/encl: Site Vice President - Dresden Nuclear Power Station
Dresden Nuclear Power Station Plant Manager
Regulatory Assurance Manager - Dresden
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
Assistant Attorney General
Illinois Emergency Management Agency
State Liaison Officer
Chairman, Illinois Commerce Commission
DOCUMENT NAME: G:\dres\ML052130286.wpd
To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy
OFFICE RIII E RIII RIII
NAME MRing
DATE 07/29/05
OFFICIAL RECORD COPY
C. Crane -3-
ADAMS Distribution:
GYS
MXB
RidsNrrDipmIipb
GEG
KGO
DRC1
CAA1
C. Pederson, DRS (hard copy - IRs only)
DRPIII
DRSIII
PLB1
JRK1
ROPreports@nrc.gov (inspection reports, final SDP letters, any letter with an IR number)
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-237; 50-249
Report No: 05000237/2005008; 05000249/2005008
Licensee: Exelon Generation Company
Facility: Dresden Nuclear Power Station, Units 2 and 3
Location: 6500 North Dresden Road
Morris, IL 60450
Dates: April 1 through June 30, 2005
Inspectors: D. Smith, Senior Resident Inspector
M. Sheikh, Resident Inspector
C. Phillips, Senior Operations Engineer
W. Slawinski, Senior Radiation Specialist
R. Winter, Reactor Engineer
L. Ramadan, Inspector, Region III
D. Melendez-Colon, Inspector, Region III
D. Reeser, Reactor Engineer
M. Gryglak, Reactor Inspector, Decommissioning Branch
R. Schulz, Illinois Emergency Management Agency
Approved by: Mark Ring, Chief
Branch 1
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000237/2005008; IR 05000249/2005008; 04/01/2005 - 06/30/2005; Exelon Generation
Company, Dresden Nuclear Power Station, Units 2 and 3; Identification and Resolution of
Problems, Event Follow-up, routine integrated report.
This report covers a 3-month period of baseline resident inspection; announced baseline
inspections on radiation material processing and transportation, operator requalification
program, maintenance rule effectiveness, and independent spent fuel storage installation
activities. The inspection was conducted by Region III inspectors and the resident inspectors.
Four Green findings, two of which involved Non-Cited Violations, 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 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 Findings
Cornerstone: Barrier Integrity
- Green. On February 8, 2005, a performance deficiency was identified by the inspectors.
The licensee failed to identify the failure of the refuel floor damper in the reactor building
ventilation system in a timely manner which resulted in the late discovery of a design
deficiency with the standby gas treatment system. The standby gas treatment system
used reactor building ventilation ductwork before directing air flow to the standby gas
treatment filters. The refuel floor damper would throttle down, per design, to ensure a
local negative differential pressure in the reactor water cleanup heat exchanger rooms
with respect to the refuel floor. As a result, air flow to the standby gas treatment system
was significantly restricted and affected the standby gas treatment recovery time for the
entire secondary containment. The damper failed prior to 2003, masking the design
deficiency, and was unnoticed until February 2005. Also, inadequate inspections of the
dampers in the reactor building ventilation system during operation of the standby gas
treatment system contributed to the late discovery of this design issue. The primary
cause of this finding was related to the cross-cutting issue of problem identification and
resolution.
The finding was greater than minor because, if left uncorrected, the failure to identify
deficient plant equipment would become a more significant safety concern because
important systems could be rendered inoperable and because it impacted the barrier
integrity cornerstone objective to provide reasonable assurance that physical design
barriers protect the public from radionuclide releases caused by accidents or events. In
addressing this issue, the licensee gagged each units refuel floor damper open to 80
percent to ensure adequate air flow to the standby gas treatment system. The finding
was of very low safety significance because the standby gas treatment system was
always able to restore secondary containment differential pressure within the Technical
Specifications allowed outage time of four hours. (Section 4OA2.3)
1 Enclosure
- Green. On May 2, 2005, a performance deficiency was identified by the inspectors. The
licensee failed to identify that corrective actions were ineffective from a previous 2004
event, involving the failure to follow the clearance order process. Also, an instrument
maintenance technician failed to properly implement annual clearance order process
training. As a result, the instrument maintenance technician removed the 2D traversing
incore probe (TIP) drawer which had a clearance order danger tag attached to the
control switch. The primary cause of this finding was related to the cross-cutting issues
of human performance and problem identification and resolution.
The finding was more than minor because, if left uncorrected, the licensees failure to
ensure plant personnel adherence to the clearance order process would become a more
significant safety concern by resulting in significant personnel safety consequences, and
because it impacted the barrier integrity cornerstone objective to provide reasonable
assurance that physical design barriers protect the public from radionuclide releases
caused by accidents or events. The removal and re-installation of the 2D traversing
incore probe drawer did not adversely affect the ability to ensure containment isolation
using the ball check containment isolation valve. The licensee briefed all maintenance
personnel on this event and added more detailed discussion on the clearance order
process to the annual site training. Therefore, this finding screened as having very low
safety significance. (Section 4OA2.6)
Cornerstone: Mitigating Systems
- Green. On December 11, 2004, a performance deficiency involving a Non-Cited
Violation of 10 CFR Part 50, Appendix B, Criterion XI and Criterion III was identified by
the inspectors. The licensee failed to perform post-modification testing and to assure
critical aspects of the core spray modification installation, which included obtaining gap
measurement for mechanical joints, verifying the capability of the tooling to produce the
required surface finishes on pre-fabricated components, and verifying that the pre-
fabricated components were properly machined, met the leakage analysis
specifications.
The finding was greater than minor because it affected the mitigating systems
cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences, specifically the
design control attribute. The finding was of very low safety significance because the
licensee was able to demonstrate, with the assistance of General Electric, that there
was reasonable assurance that the modification was installed properly. The licensee
planned to revise CC-AA-107, Configuration Change Acceptance Testing Criteria,
and/or CC-AA-107-1001, Post Modification Acceptance Testing. The procedure
change would provide that the substitution for post modification testing would ensure
quality at least equivalent to that specified in the original design bases. In addition, the
licensee planned to confirm that the installed core spray modification had been installed
with a level of quality equivalent to the original design basis. (Section 4OA3.1)
- Green. On September 29, 2004, a performance deficiency involving a Non-Cited
Violation of 10 CFR Part 50, Appendix B, Criterion XVI, was identified by the inspectors.
The licensee had implemented inadequate corrective actions for a deficient condition
2 Enclosure
that occurred on September 6, 1996, to prevent recurrence of a similar deficient
condition that occurred on September 29, 2004. Both events involved the failure of
safety related time delay relays to meet acceptance criteria due to the use of a
stopwatch as a tool for calibration of safety related equipment. The primary cause of
this finding was related to the cross-cutting issue of problem identification and
resolution.
The finding was greater than minor because it impacted the mitigating system
cornerstone objective to ensure availability, reliability, and capability of systems that
respond to initiating events and because it affected the reliability of a safety related
component. As a result of the 2004 event, the licensee initiated issue report 258172,
created an action item to review the root cause of the event, revised the isolation
condenser initiation time delay relay calibration procedure to require the use of a strip
chart recorder, and created an action item to evaluate the extent of condition. The
finding was of very low safety significance because the isolation condenser system did
not lose the ability to perform its safety function and all other mitigating systems were
available. (Section 4OA3.3)
B. Licensee Identified Findings
No findings of significance were identified.
3 Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 2 began the inspection period at 912 MWe (95 percent thermal power and 100 percent of
rated electrical capacity).
- On May 28, 2005, the unit was taken off line for main generator hydrogen seal
maintenance. The unit returned to full power on June 2, 2005.
- On June 3, 2005, the unit downpowered to 767 MWe for control rod pattern adjustment,
and returned to full power on the same day.
Unit 3 began the inspection period at 912 MWe (95 percent thermal power and 100 percent of
rated electrical capacity).
- On April 26, 2005, the unit was taken offline to replace the 3B reactor recirculation pump
seal. The unit returned to full power on May 1, 2005.
- On May 8, 2005, the unit downpowered to 773 MWe for control rod pattern adjustment,
and returned to full power on the same day.
- On June 2, 2005, the unit downpowered to 150 MWe due to a electro-hydraulic control
system oil leak in the turbine front standard. The unit returned to full power on June
4, 2005.
- On June 16, 2005, the unit downpowered to 815 MWe due to an unexpected isolation of
a feedwater heater string, and returned to full power on the same day.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04 Equipment Alignment (71111.04Q and S)
.1 Partial System Walkdowns
a. Inspection Scope
The inspectors selected a redundant or backup system to an out-of-service or degraded
train, reviewed documents to determine correct system lineup, and verified critical
portions of the system configuration. Instrumentation valve configurations and
appropriate meter indications were also observed. The inspectors observed various
support system parameters to determine the operational status. Control room switch
positions for the systems were observed. Other conditions, such as adequacy of
housekeeping, the absence of ignition sources, and proper labeling were also
evaluated.
4 Enclosure
The inspectors performed partial equipment alignment walkdowns of the:
- Unit 2/3 A train standby gas treatment system;
- Unit 3 B train core spray system;
- Unit 2 Division I direct current system and Unit 3 Division II direct current system;
and
- Unit 2 A train core spray system.
This represented four inspection samples.
b. Findings
No findings of significance were identified.
.2 Complete Walkdown
a. Inspection Scope
The inspectors performed a complete semiannual walkdown of the Unit 3 containment
cooling service water system to verify proper alignment, component accessibility,
availability, and current condition. The inspectors reviewed selected system operating
procedures, surveillance procedures, mechanical and electrical lineups, drawings, and
the Updated Final Safety Analysis Report (UFSAR) to identify proper system alignment.
The inspectors reviewed outstanding work orders associated with the system to
determine whether there were any deficiencies that could affect the ability of the system
to perform its safety related function. The inspectors also reviewed selected licensee
condition reports (CR) and issue reports (IR) to verify the effectiveness of completed
corrective actions of past issues.
This represented one inspection sample.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05)
a. Inspection Scope
The inspectors toured plant areas important to safety to assess the material condition,
operating lineup, and operational effectiveness of the fire protection system and
features. The review included control of transient combustibles and ignition sources, fire
suppression systems, manual fire fighting equipment and capability, passive fire
protection features, including fire doors, and compensatory measures. The following
areas were walked down:
- Unit 2 reactor building, elevation 476'-6" west low pressure coolant injection
corner room, Fire Zone 11.2.1;
5 Enclosure
- Unit 2/3 emergency swing diesel generator building, elevation 517' of the
emergency diesel generator room, Fire Zone 9.0.C;
- Unit 2/3 turbine building, elevation 534' switchgear area, Fire Zone 8.2.6.A;
- Unit 2 reactor building, elevation 476' 6" torus basement, Fire Zone 1.1.1.1;
- Unit 3 turbine building, elevation 517' switchgear area, Fire Zone 8.2.5.E;
- Unit 2 turbine building, elevation 517' emergency diesel generator room, Fire
Zone 9.0.A; and
- Unit 2 turbine building, elevation 517' trackway, Fire Zone 8.2.5.A.
This represented seven inspection samples.
b. Findings
No findings of significance were identified.
1R06 Flooding (71111.06)
a. Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report (USFAR)
Section 3.4.1.2 for internal flood analysis and reviewed the licensees procedure for
internal flooding. The inspectors walked down the Unit 2/3 cribhouse to verify
compliance with the licensees UFSAR and reviewed the licensees previously
implemented corrective actions for deficiencies associated with internal flood protection.
This represented one inspection sample.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11A and Q)
.1 Annual Operating Test Results
a. Inspection Scope
The inspectors reviewed the overall pass/fail results of the annual operating examination
which consisted of Job Performance Measure operating tests, and simulator operating
tests (required to be given per 10 CFR 55.59(a)(2)) administered by the licensee from
May 3 through June 1, 2005. In addition, the inspectors reviewed the overall pass/fail
results for the biennial written examination (also required to be given per 10 CFR
55.59(a)(2)) administered by the licensee from May 4 through June 10, 2005. The
overall results were compared with the significance determination process in
accordance with NRC Manual Chapter 0609, Operator Requalification Human
Performance Significance Determination Process.
This represented one inspection sample.
6 Enclosure
b. Findings
No findings of significance were identified.
.2 Licensed Operator Requalification Program
a. Inspection Scope
The inspectors observed an evaluation of operating crew #3 on June 1, 2005. The
scenario consisted of a loss of instrument air (recoverable), loss of motor control
center 28-7/29-7, and a recirculation line break resulting in containment flooding. The
inspectors verified that the operators were able to complete the tasks in accordance with
applicable plant procedures. The inspectors observed the licensees evaluators to
ensure that no inappropriate cues were provided by the evaluators while assessing the
operators' performance. In addition, the inspectors verified that issue reports written
regarding licensed operator requalification training were entered into the licensees
corrective action program with the appropriate significance characterization.
This represented one inspection sample.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12B and Q)
.1 Periodic Evaluation
a. Inspection Scope
The inspectors examined the periodic evaluation report completed for the period of
October 1, 2002 through September 30, 2004. To evaluate the effectiveness of (a)(1)
and (a)(2) activities, the inspectors examined a sample of Dresden (a)(1) Action Plans,
performance criteria, functional failures, and issue reports. These same documents
were reviewed to verify that the threshold for identification of problems was at an
appropriate level and the associated corrective actions were appropriate. Also, the
inspectors reviewed the maintenance rule procedures and processes. The inspectors
focused the inspection on the following four systems (samples):
- Direct current electric system;
- High pressure core injection system (HPCI);
- Containment cooling service water system (CCSW); and
- Hardened containment vent system.
The inspectors verified that the periodic evaluation was completed within the time
restraints defined in 10 CFR 50.65 (once per refueling cycle, not to exceed 24 months).
The inspectors also ensured that the licensee reviewed its goals, monitored structures,
systems, and components (SSCs) performance, reviewed industry operating
7 Enclosure
experience, and made appropriate adjustments to the maintenance rule program as a
result of the above activities;
The inspectors verified that the licensee balanced reliability and unavailability during the
previous refueling cycle, including a review of high safety significant SSCs;
The inspectors verified that (a)(1) goals were met, that corrective action was appropriate
to correct the defective condition, including the use of industry operating experience,
and that (a)(1) activities and related goals were adjusted as needed; and
The inspectors verified that the licensee has established (a)(2) performance criteria,
examined any SSCs that failed to meet their performance criteria, and reviewed any
SSCs that have suffered repeated maintenance preventable functional failures including
a verification that failed SSCs were considered for (a)(1).
In addition, the inspectors reviewed maintenance rule self-assessments that addressed
the maintenance rule program implementation.
This represented one inspection sample.
b. Findings
No findings of significance were identified.
.2 Routine Inspection
a. Inspection Scope
The inspectors reviewed the licensee's handling of performance issues and the
associated implementation of the Maintenance Rule (10 CFR 50.65) to evaluate
maintenance effectiveness for the selected systems. The following systems were
selected based on being designated as risk significant under the Maintenance Rule,
being in the increased monitoring (Maintenance Rule category a(1)) group, or due to an
inspectors identified issue or problem that potentially impacted system work practices,
reliability, or common cause failures:
- Unit 2 emergency diesel generator system; and
- Unit 3 miscellaneous sumps and drains system.
The inspectors verified the licensee's categorization of specific issues, including
evaluation of the performance criteria, appropriate work practices, identification of
common cause errors, extent of condition, and trending of key parameters. Additionally,
the inspectors reviewed the licensee's implementation of the maintenance rule
requirements, including a review of scoping, goal-setting, performance monitoring,
short-term and long-term corrective actions, functional failure determinations associated
with the condition and issue reports reviewed, and current equipment performance
status.
This represented two inspection samples.
8 Enclosure
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors evaluated the effectiveness of the risk assessments performed before
maintenance activities were conducted on structures, systems, and components and
verified how the licensee managed the risk. The inspectors evaluated whether the
licensee had taken the necessary steps to plan and control emergent work activities.
The inspectors also verified that equipment necessary to complete planned contingency
actions was staged and available. The inspectors completed evaluations of
maintenance activities on the:
- Unit 2 maximum combined flow limiter setting adjustment;
- Unit 3 Division 1 core spray logic system functional testing;
- Unit 2 Division 1 low pressure coolant injection containment cooling water logic
system functional testing;
- Unit 3 125 Vdc battery charger #3 removal from service; and
- Unit 2 and Unit 3 concurrent performance of surveillances associated with the
core spray system, high pressure coolant injection system, and standby liquid
control system.
This represented five inspection samples.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors reviewed operability evaluations to ensure that operability was properly
justified and the component or system remained available, such that no unrecognized
increase in risk occurred. The review included issues involving the operability of:
- Unit 2 B service water pump did not trip (IR 324995);
- Unit 2/3 time for standby gas treatment system to recover reactor building
differential pressure abnormally long (IR 320258); and
- Unit 2 isolation condenser steam supply vent lines (engineering changes 352592
and 353273).
This represented three inspection samples.
9 Enclosure
b. Findings
No findings of significance were identified.
1R16 Operator Work-Around (71111.16)
Semi-annual Review of the Cumulative Effects of Operator Workarounds
a. Inspection Scope
The inspectors reviewed all operator workarounds and challenges to assess any
cumulative effect on the :
- reliability, availability, and potential for misoperation of a system;
- multiple mitigating systems; and
- ability of operators to respond in a correct and timely manner to plant transients
and accidents.
This represented one inspection sample.
b. Findings
No findings of significance were identified.
1R19 Post Maintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed post-maintenance test results to confirm that the tests were
adequate for the scope of the maintenance completed and that the test data met the
acceptance criteria. The inspectors also reviewed the tests to determine if the systems
were restored to the operational readiness status consistent with the design and
licensing basis documents. The inspectors reviewed post-maintenance testing activities
associated with the following:
- Unit 3 containment cooling service water scupper drain check valve, 3-4999-75
inspection;
- Unit 2/3 emergency diesel generator cooling water pump replacement;
- Unit 2/3 emergency diesel generator power packs replacement, installation of
flex house, replacement of 2/3 diesel generator coolant water pump with
stainless steel design; and
- Unit 2 B service water pump breaker trip coil replacement.
This represented four inspection samples.
10 Enclosure
b. Findings
.1 Inability to Trip the 2B Service Water Pump from the Control Room
Introduction: The inspectors identified an unresolved item regarding the adequacy of
installation of sixteen trip coil mechanisms for breakers on Unit 2 safety related 4KV
buses 23 and 24.
Description: On April 15, 2005, while swapping service water (SW) pumps, the onshift
operator started the 2A SW pump and then attempted to secure the 2B SW pump by
placing the control switch in the normal-after-trip position. However, the pump did not
trip as indicated by the motor amperage reading, and the light indication for the pump
did not illuminate. Subsequently, the onshift operator placed the control switch in the
pull-to-lock position, but the 2B SW pump continued to run. A non-licensed operator
was dispatched locally to bus 24 and tripped the pump with the local trip pushbutton on
the breaker.
On April 20, 2005, the licensee informed the residents that the tripping capability of the
2B SW water pump was lost due to the incorrect installation of the pumps trip coil
mechanism. Initially, the licensee considered this installation error to be generic in
nature and to have existed since 1995. The inability to trip the 2B SW pump was of
concern because bus 24 could be lost due to the inability to shed this load from the bus
during an accident. This bus was the power supply source for the Division II
containment cooling service water system pumps.
Subsequently, the licensee determined that the 2B SW pump was worked on
February 15, 2005, under Work Order (WO) 00727085-01. The work was to clean and
inspect the close latch reset mechanism on the breaker for hardened lubricant. The
WO included the appropriate information from the vendor manual on how to perform the
work; however, the electrician installed the trip coil incorrectly. The WO provided an
optional instructional step for post-maintenance testing, which specified verification of
the electrical operation of the breaker. Because this step was not required to be
performed, the post maintenance test did not identify that the 2B SW pump would not
trip from the control room after the incorrect installation of the trip coil mechanism. The
licensee proceeded with inspecting the installation of the trip coil mechanisms for all the
potentially affected breakers even though the licensee suspected that the inadequate
work on the 2B SW pump was an isolated case of poor human performance.
The licensee performed inspections of all the applicable Unit 3 breakers during the
April 2005 forced outage. The inspections confirmed that all trip coils had been properly
installed. Initially, the licensee was able to verify proper installation of the trip coils for
several breakers on Unit 2 that had their associated breaker opened since the
equipment was not in service. Four more breakers were inspected, with satisfactory
results, during the 2005 May maintenance outage. The remaining 16 breakers will be
inspected during the Fall 2005 refueling outage because the licensee was concerned
that the inspection activity, which involved the removal of the breaker cover, could
adversely impact plant operations. This issue will be an Unresolved Item (URI) pending
inspector review of the results of the inspections on the remaining breakers.
11 Enclosure
1R20 Outage Activities (71111.20)
.1 Unit 3 Maintenance Outage
a. Inspection Scope
The licensee conducted a maintenance outage on Unit 3 from April 26-May 1, 2005.
During the outage the licensee replaced the 3B reactor recirculation pump seal, repaired
the 3B master trip solenoid valve, replaced the 3E electromatic relief valve, and
assessed the condition of the strain gauges on the main steam lines and made
appropriate repairs.
The inspectors verified that the licensee effectively conducted the shutdown, managed
elements of risk pertaining to reactivity control during and after the shutdown, and
implemented decay heat removal system procedure requirements as applicable. The
inspectors performed the following activities daily:
- attended control room operator and outage management turnover meetings to
verify that the current shutdown risk status was well understood and
communicated;
- performed walkdowns of containment to identify any indications of unidentified
leakage;
- ensured that the control room operators adhered to the plants Technical
Specifications;
- performed walkdowns of the main control room to observe the alignment of
systems important to shutdown risk;
- reviewed selected issues that the licensee entered into the corrective action
program to verify that identified problems were being entered into the program
with the appropriate characterization and significance;
- ensured that the licensee appropriately considered risk factors during the
development and execution of planned activities;
- monitored licensees troubleshooting efforts for emergent plant equipment
issues;
- performed plant walkdowns to observe ongoing work activities;
- observed control rod withdrawals and initial transition to criticality;
- performed walkdown of containment prior to closure to ensure that debris had
not been left that could affect the performance of the containment sumps; and
- monitored Mode switch changes and observed portions of power ascension.
b. Findings
No findings of significance were identified.
.2 Unit 2 Maintenance Outage
a. Inspection Scope
On May 28, 2005, the licensee commenced a four day maintenance outage on Unit 2 to
replace the #10 main turbine generator seal. During the outage, the reactor remained
12 Enclosure
critical at approximately 20 percent power. The licensee replaced the 2A stator cooling
water pump, calibrated the bus duct temperature alarms, and repaired the turbine
generator thrust bearing wear detector.
The inspectors verified that the licensee effectively removed the turbine from service,
conducted the downpower, and managed elements of risk pertaining to reactivity control
during and after the downpower.
The inspectors performed the following activities daily:
- attended control room operator and outage management turnover meetings to
verify that the current online risk status was well understood and communicated;
- ensured that the control room operators adhered to the plants technical
specifications;
- performed walkdowns of the main control room to observe the alignment of
systems important to shutdown risk;
- reviewed selected issues that the licensee entered into the corrective action
program to verify that identified problems were being entered into the program
with the appropriate characterization and significance;
- ensured that the licensee appropriately considered risk factors during the
development and execution of planned activities;
- monitored licensee troubleshooting efforts for emergent plant equipment issues;
and
- performed plant walkdowns to observe ongoing work activities.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors observed surveillance testing on risk-significant equipment and reviewed
test results. The inspectors assessed whether the selected plant equipment could
perform its intended safety function and satisfy the requirements contained in Technical
Specifications. Following the completion of each test, the inspectors determined that
the test equipment was removed and the equipment returned to a condition in which it
could perform its intended safety function.
The inspectors observed surveillance testing activities and/or reviewed completed
packages for the tests, listed below, related to systems in the initiating event, mitigating
systems, and barrier integrity cornerstones:
- Dresden Operating Surveillance (DOS) 1600-29, Unit 2 and 3 Drywell
Temperature Surveillance, Revision 4
RPS Reserve Power Supply EPAs, Revision 2;
13 Enclosure
- Dresden Instrument Surveillance (DIS) 1400-05, Division 1 Core Spray System
Functional Test, Revision 26;
- DIS 1400-05, Division 2 Core Spray System Functional Test, Revision 26;
- DIS 1500-27, Division 1 Low Pressure Coolant Injection Containment Cooling
Logic System Functional Test, Revision 5;
- Unit 2(3), Appendix A, Reactor Coolant System Leakage, Revision 98; and
- DOS 6620-07, Station Black Out 2 (3) Diesel Generator Surveillance Tests,
Revision 18.
This represented seven inspection samples.
b. Findings
No findings of significance were identified.
1R23 Temporary Modification (71111.23)
a. Inspection Scope
The inspectors screened one active temporary modification and assessed the effect of
the temporary modification on safety-related systems. The inspectors also determined if
the installation was consistent with system design:
- Temporary Change Configuration Package 354622, Install Temporary Jumper
at Electro Hydraulic Control System Card 2-5640-A37 (in Cabinet 2-0902-31) to
Bypass the Function of A Main Steam Pressure Regulator.
This represented one inspection sample.
b. Findings
No findings of significance were identified.
1EP6 Drill and Training Evaluation (71114.06)
.1 Evaluation of Operating Crew #6 Training Evolution
a. Inspection Scope
The inspectors evaluated the training evolution to assess the licensees performance
and to determine if the training was of the appropriate scope to be included in the
performance indicator statistics. The inspectors observed Crew #6 on May 11, 2005.
The scenario consisted of spurious isolation of high pressure coolant injection system,
control rod drive system leak and accumulator trouble, anticipated transient without
scram, and reactor building high radiation.
This represented one inspection sample.
14 Enclosure
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Public Radiation Safety
2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems (71122.01)
.1 Inspection Planning
a. Inspection Scope
The inspectors reviewed the licensees current revision to the Offsite Dose Calculation
Manual (ODCM) and the licensees Radioactive Effluent Release Reports for calendar
years 2002, 2003, and 2004, along with selected radioactive effluent release data for
2005 through April 2005. The inspectors verified that technical evaluations were
completed for modifications to the ODCM since the last inspection of this program area
in 2003, and that effluent radiation monitor setpoints were changed accordingly since
completion of those modifications, as warranted. The inspectors also reviewed self-
assessments, audits, and licensee event reports that involved unanticipated offsite
releases of radioactive effluents, as applicable. The effluent reports, effluent data, and
licensee evaluations were reviewed to verify that the radioactive effluent control program
was implemented as required by the radiological effluent technical specifications (RETS)
and the ODCM, to verify that public dose limits from effluents were not exceeded, and to
ensure that any anomalies in effluent release data were adequately understood by the
licensee and were properly assessed and reported.
The inspectors reviewed the ODCM to identify the gaseous and liquid effluent radiation
monitoring systems and associated effluent flow paths including in-line flow
measurement devices, and reviewed the description of radioactive waste systems and
effluent pathways provided in the UFSAR in preparation for the onsite inspection.
These reviews represented one inspection sample.
b. Findings
No findings of significance were identified.
.2 Onsite Inspection - Walkdown of Effluent Control Systems, System/Program
Modifications, and Instrument Calibrations
a. Inspection Scope
The inspectors walked down the readily accessible components of the gaseous and
liquid release systems (e.g., radiation and flow monitors, tanks, and vessels) and the
radwaste control room to observe current system configuration with respect to the
15 Enclosure
description in the UFSAR, to discuss ongoing activities with radwaste operations staff,
and to assess equipment material condition. Records of material condition surveillances
performed since 2004 for those tanks and vessels located in locked high radiation areas
were reviewed to determine the extent of any problems and the licensees corrective
actions.
The inspectors reviewed the technical justification for any changes made by the licensee
to the ODCM, as well as changes to the liquid or gaseous radioactive waste system
design or operation since the last inspection to determine whether these changes
affected the licensees ability to maintain effluents as low as reasonably achievable and
whether changes made to monitoring instrumentation resulted in non-representative
monitoring of effluents. Radioactive effluent release reports for the three years
preceding the inspection were evaluated for any significant changes (factor of 5) in
either the quantities or kinds of radioactive effluents and for any significant changes in
offsite dose which could be indicative of problems with the effluent control program. No
significant adverse changes were identified.
The inspectors reviewed records of the most recent instrument calibrations for each
point-of-discharge effluent radiation monitor and for selected effluent flow measurement
devices to determine if they had been calibrated consistent with industry standards and
in accordance with station procedures, technical specifications and the ODCM.
Specifically, the inspectors reviewed calibration records for the following effluent
radiation monitors and flow measuring devices:
- Unit 2/3 reactor building vent (station particulate, iodine and noble gas (SPING))
monitor;
- Unit 2/3 main chimney (backup) noble gas monitor;
- Unit 2/3 main chimney SPING monitor;
- Unit 2 and Unit 3 service water effluent gross activity monitors;
- Unit 2/3 liquid radwaste effluent gross activity monitor;
- Unit 2 and Unit 3 isolation condenser vent radiation monitors;
- Unit 2/3 main chimney flow rate monitoring device; and
- Unit 2/3 reactor building vent flow rate monitoring device.
The inspectors also reviewed effluent radiation monitor setpoint bases and alarm
setpoint values for these monitors to verify their technical adequacy and for compliance
with ODCM criteria. Additionally, the inspectors discussed with system engineering staff
the availability and performance of the above listed effluent monitors and discussed the
corrective actions underway to address historical problems with the service water
monitors.
The inspectors reviewed chemistry department quality control data for those
instrumentation systems used to quantify effluent releases. Specifically, the inspectors
reviewed the most recent efficiency calibration records and lower limit of detection
determinations for Chemistry Department gamma spectroscopy systems and for the
liquid scintillation counter.
These reviews represented three inspection samples.
16 Enclosure
b. Findings
No findings of significance were identified.
.3 Onsite Inspection - Effluent Release Packages, Abnormal Releases, Dose Calculations,
and Laboratory Analytical Quality Control
a. Inspection Scope
The inspectors selectively reviewed batch liquid effluent release packages and gaseous
effluent sampling data for selected periods in 2004 through April 2005, including results
of chemistry sample analyses, the application of vendor laboratory analysis results for
difficult to detect nuclides, and the licensees effluent release procedures and practices.
Additionally, the inspectors reviewed the methods for calculating the projected doses to
members of the public from these releases. These reviews were performed to verify
that the licensee adequately applied analysis results in its dose calculations consistent
with ODCM methodology, and to determine if effluents were released in accordance with
the RETS/ODCM and procedural requirements.
The inspectors accompanied chemistry staff to observe the routine weekly change-out
of the particulate and iodine samplers and the collection of a noble gas sample from the
Unit 2/3 main chimney to determine if sampling practices, sampler restoration and
analytical techniques were sound and consistent with procedure.
The inspectors reviewed records of abnormal/unmonitored releases that the licensee
identified and documented in its 2003 and 2004 annual effluent reports and discussed
the methods used to quantify these releases. The inspectors also reviewed the
licensees practices for compensatory sampling during periods of effluent monitor
inoperability to verify compliance with ODCM requirements.
The inspectors reviewed a selection of quarterly and annual dose calculations to ensure
that the licensee properly calculated the offsite dose from radiological effluent releases
and to determine if any annual RETS/ODCM (i.e., Appendix I to 10 CFR Part 50) design
objectives (limits) were exceeded.
The inspectors reviewed the results of the quarterly radiochemistry inter-laboratory
cross-check comparisons for the five calendar quarters preceding the inspection to
validate the licensees analyses capabilities. The inspectors reviewed the licensees
evaluation of any disparate inter-laboratory comparisons and the associated corrective
actions for any deficiencies identified, as applicable. In addition, the inspectors
reviewed the results of the licensees 2003 and 2004 quality assurance audits of the
RETS/ODCM program.
These reviews represented four inspection samples.
b. Findings
No findings of significance were identified.
17 Enclosure
.4 Air Cleaning System Surveillance Tests
a. Inspection Scope
The inspectors reviewed the most recent results for both trains of the Unit 2/3 standby
gas treatment (SBGT) system ventilation system filter testing to verify that test methods,
frequency, and test results met technical specification requirements. Specifically, the
inspectors reviewed the results of in-place high efficiency particulate air (HEPA) and
charcoal absorber penetration tests, laboratory tests of charcoal absorber methyl iodide
penetration and in-place tests of pressure differential across the combined HEPA
filters/charcoal absorbers for the SBGT.
These reviews represented one inspection sample.
b. Findings
No findings of significance were identified.
.5 Identification and Resolution of Problems
a. Inspection Scope
The inspectors reviewed licensee self-assessments, audits, and special reports related
to the radioactive effluent treatment and monitoring program since the last inspection to
determine if identified problems were entered into the corrective action program for
resolution. The inspectors also verified that the licensee's problem identification and
resolution program together with its audit and self-assessment program were capable of
identifying repetitive deficiencies or significant individual deficiencies in problem
identification and resolution.
The inspectors reviewed various corrective action reports related to the radioactive
effluent treatment and monitoring program generated since 2004, interviewed staff, and
reviewed documents to determine if the following activities were being conducted in an
effective and timely manner commensurate with their importance to safety and risk:
- Initial problem identification, characterization, and tracking;
- Disposition of operability/reportability issues;
- Evaluation of safety significance/risk and priority for resolution;
- Identification of repetitive problems;
- Identification of contributing causes;
- Identification and implementation of effective corrective actions; and
- Implementation/consideration of risk significant operational experience feedback.
These reviews represented one inspection sample.
b. Findings
No findings of significance were identified.
18 Enclosure
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
Cornerstone: Public Radiation Safety
.1 Radiation Safety Strategic Area
a. Inspection Scope
The inspectors sampled the licensees submittals for the performance indicator (PI)
listed below for the period indicated. The inspectors used PI definitions and guidance
contained in Revision 2 of Nuclear Energy Institute Document 99-02, Regulatory
Assessment Performance Indicator Guideline, to verify the accuracy of the PI data.
The following PI was reviewed:
- Radiological Effluent Technical Specification/Offsite Dose Calculation Manual
Radiological Effluent Occurrence.
The inspectors reviewed the licensees CR database and selected CRs generated since
this indicator was last reviewed in June 2004, to identify any potential occurrences such
as unmonitored, uncontrolled, or improperly calculated effluent releases that may have
significantly impacted offsite dose. The inspectors reviewed gaseous and liquid effluent
summary data and the results of associated offsite dose calculations for 2004 to
determine if indicator results were accurately reported. Additionally, the inspectors
discussed with chemistry staff its methods for quantifying effluents and determining
effluent dose.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
.1 Routine Quarterly Review
a. Inspection Scope
As discussed in previous sections of this report, the inspectors routinely reviewed issues
during baseline inspection activities and plant status reviews to verify that they were
being entered into the licensees corrective action system at an appropriate threshold,
that adequate attention was being given to timely corrective actions, and that adverse
trends were identified and addressed. Minor issues entered into the licensees
corrective action system as a result of inspectors observations are generally denoted in
the report. In addition, in order to help identify repetitive equipment failures or specific
human performance issues for follow-up, the inspectors performed a daily screening of
items entered into the licensees corrective action program. This review was
19 Enclosure
accomplished by reviewing daily issue reports and attending daily issue report review
meetings.
b. Findings
No findings of significance were identified.
.2 Semiannual Review for Trends
a. Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems,
the inspectors performed a review of the licensees corrective action program (CAP) and
associated documents to identify trends that could indicate the existence of a more
significant safety issue. The inspectors review consisted of a six month period from
January 2005 through June 2005, although some examples expanded beyond those
dates when the scope of the trend warranted. The inspectors reviewed multiple issue
reports generated during the time period of January through June 2005, in an attempt to
identify potential trends. The screening was accomplished as follows:
1. IRs dealing with company policies, administrative issues, and other minor issues
were eliminated as being outside the scope of this inspection;
2. The IRs were sorted into categories involving same equipment problems,
repetitive issues, reoccurring departmental problem/challenges and repeated
entries into technical specifications. The IRs were then screened for potential
common cause issues and considered for potential trends;
3. The inspectors removed groups of IRs that discussed strictly programmatic
problems because the inspection requirement was primarily for equipment
problems and human performance issues;
4. The inspectors removed groups of IRs that discussed security issues, those will
be reviewed and documented as necessary in a separate report during a future
inspection by a security specialist;
5. The inspectors also removed groups of IRs where their review indicated that
duplicate IRs had been written for the same event or failure;
6. The inspectors obtained a list of all licensee common cause investigations
initiated in the last six months. All IRs in which the title indicated a trend or
potential adverse trend were considered licensee-identified trends;
7. The remaining groups, considered potential unidentified trends, were provided to
the licensee for discussion in case there was extenuating information that the
inspectors were not aware of; and
8. Groups of IRs remaining after all of the above screening were considered trends
which the licensee had failed to identify.
20 Enclosure
9. The inspectors then were able to make an assessment by comparing the trends
identified by the licensee to those trends identified by the NRC.
In addition, the inspectors reviewed corrective action backlog lists and all of the nuclear
oversight assessments and audits conducted during January to June of 2005.
This represented one inspection sample.
b. Findings
There were no findings of significance identified. The inspectors determined that
licensee employees were writing issue reports at an appropriate threshold, and that
employees at all levels of the organization were writing IRs. The inspectors determined
that the licensee had identified the same specific trends as the inspectors. Overall, the
licensee identified issues adequately and entered them into their corrective action
program.
.3 Secondary Containment Differential Pressure (dP)
a. Inspection Scope
The inspectors reviewed issue reports associated with the loss of secondary
containment dP and the inability to maintain secondary containment dP at the required
Technical Specifications (TS) value of -0.25 inch dP when starting one train of the SBGT
system either automatically or manually.
This represented one inspection sample.
b. Findings
Introduction: A Green finding was identified by the inspectors involving the licensees
failure to identify the failure of a damper in the reactor building ventilation system in a
timely manner, and the licensee's failure to identify a design deficiency during operation
of the SBGT system. The licensee identified the damper failure on February 8, 2005.
However, the damper had been in a failed open condition since 2003. The failed open
damper allowed significant additional air flow and masked a design deficiency with air
flow to the SBGT system. The amount of air flow to the SBGT system was significantly
restricted when the failed damper was repaired, which delayed the ability of the SBGT
system to restore secondary containment dP to -0.25 inch.
Description: The inspectors reviewed the control room logs and determined that there
were eight occasions between January 14, 2005 and May 20, 2005, where there were
problems with the SBGT system maintaining secondary containment to -0.25 inch dP.
During the first six instances, one train of the SBGT system was able to restore
secondary containment dP to -0.25 inch within 5 to 15 minutes. Other variables which
contributed to the normal recovery times of 5 to 15 minutes included wind speed, and
the resultant 28 square foot opening in secondary containment that existed until the
reactor building ventilation isolation valves closed due to the delay time between
21 Enclosure
manually securing reactor building ventilation fans and closing the reactor building
ventilation isolation valves.
On April 1, 2005, the seventh occurrence, after manually starting one train of the SBGT
system and manually isolating the reactor building ventilation system, secondary
containment was not restored to -0.25 inch dP until 56 minutes later. On May 20, 2005,
the SBGT system automatically started when a refueling floor radiation monitor failed
high. Secondary containment was not recovered to -0.25 inch dP until 12 minutes and
had reached a positive value for approximately one minute. In addition to this
occurrence where secondary containment went positive, the licensee determined that
there were 51 other times when secondary containment went positive between July
26, 2001 and January 24, 2005.
As a result of the April 1, 2005 event, the inspectors challenged the acceptability of
reactor building ventilation and SBGT performance with respect to the time required to
restore secondary containment to -0.25 inch dP. The licensee conducted an
investigation into the April 1, 2005 event. The licensee documented in apparent cause
evaluation 320358 that the excessive 56 minute recovery time was due to an inadequate
design, which had existed since original plant operation, and inadequate inspections of
the reactor building ventilation system.
The SBGT system was designed to maintain Unit 2 and 3 secondary containment at
-0.25 inch dP by using reactor building ductwork and controls to ensure all radioactive
particles were processed through the SBGT system before releasing to the
environment. The reactor building ventilation system has a significantly higher flow rate
than the SBGT system. This flow rate difference between the systems was the reason
why the restricted air flow affected the SBGT system and not the reactor building
ventilation system. One dP controller, #2-5703-15, controlled 14 dampers, including the
refuel floor damper on each unit, #2/3-5772-58. The operation of the SBGT system was
adversely affected by the operation of this dP controller when the refuel floor damper
was operating correctly. The dP controller controlled area dP control dampers to ensure
the regenerative and non-regenerative heat exchanger rooms were maintained at a
negative pressure relative to the refuel floor. If a negative dP was not maintained
between these rooms and the refuel floor, dP controller #2-5703-15 would throttle down
all 14 area control dampers and force air to be drawn from these two heat exchanger
rooms. Since the SBGT system used the reactor building ventilation ductwork prior to
directing flow to the SBGT system, the throttling down response of the 14 area control
dampers restricted the air flow available to the SBGT system and delayed the systems
ability to restore the entire secondary containment to -0.25 inch dP.
Refuel floor damper #2-5772-58, had failed full open and remained in this position
from 2003 until February 8, 2005 and masked the air flow restriction problem to the
SBGT system. As a result of this damper failing open, when dP controller #2-5703-15
sent signals to all 14 dampers to throttle down, the SGBT system was able to draw a
significant amount of flow through this damper from the refueling floor and restore
secondary containment to -0.25 inch dP much sooner. After damper #2-5772-58 was
repaired on March 14, 2005, and capable of throttling down, the SBGT system would
experience excessive recovery times in restoring secondary containment based on the
severely restricted air flow to the SBGT system. The overall result was that the ability of
22 Enclosure
the SBGT system to restore total secondary containment was negatively impacted
based on the design of dP controller #2-5703-15. The inspectors determined and the
licensee agreed that there was a lack of sensitivity toward the loss of secondary
containment as supported by the 52 times that secondary containment went positive.
The licensee addressed this design deficiency by gagging the refuel floor damper on
each unit open by 80 percent. This action ensured adequate air flow to the SBGT
system and thus would allow timely restoration of secondary containment.
Analysis: The inspectors determined that the licensees failure to identify the failure of
refuel floor damper #2-5772-58 in a timely manner, which delayed the licensees
discovery of a design deficiency with the SBGT system, was a performance deficiency
warranting a significance evaluation. The inspectors concluded that the finding was
greater than minor in accordance with Inspection Manual Chapter (IMC) 0612, Power
Reactor Inspection Reports, Appendix B, Issue Screening, issued on May 19, 2005.
The inspectors concluded that the finding, if left uncorrected, would become a more
significant safety concern by potentially rendering safety related equipment inoperable
and because it impacted the barrier integrity cornerstone objective to provide reasonable
assurance that physical design barriers protect the public from radionuclide releases
caused by accidents or events. The flow to the SBGT system was significantly
restricted when damper #2-5772-58 operated as designed. The restricted air flow
delayed the ability of the SBGT system to restore secondary containment to -0.25 inch
dP. Although the SGBT system was adversely impacted by the refuel floor damper, the
SBGT system always restored secondary containment within the four hour TS allowed
outage time. The primary cause of this finding was related to the cross-cutting issue of
problem identification and resolution.
The inspectors completed a Phase 1 significance determination of this issue using
IMC 0609, Significance Determination Process, Appendix A, Attachment 1, dated
December 1, 2004. The inspectors concluded that the finding impacted the barrier
integrity cornerstone. The inspectors answered Yes to question 1 under the
containment barrier cornerstone column, in that, the finding only affected the SBGT and
reactor building ventilation systems. Therefore, this finding is of very low safety
significance (Green).
Enforcement: No violations of NRC requirements occurred because the finding involved
the reactor building ventilation system which is a non-safety related system. The
licensee entered this issue into the stations corrective action program as IR 320258.
The licensee implemented several corrective actions which included immediately
gagging open the refuel floor damper on each unit. The licensee subsequently changed
the set point of the differential pressure controller which would throttle the 14 dampers
less and thus ensure the restoration of secondary containment in a more timely manner.
(Finding (FIN)05000237/2005008-02; 05000249/2005008-02)
.4 Unit 2/3 Cribhouse Sump Pump Failure
The inspectors reviewed IR 331423. On May 3, 2005, the licensee entered Dresden
Operating Abnormal Procedure (DOA) 40-02, Localized flooding in plant, Revision 15,
due to the accumulation of 6 - 8" of water in the 2/3 cribhouse. The flooding occurred
due to the failure of the sump pumps limit switches which prevented the sump pumps
23 Enclosure
from starting on a high water level condition in the sump. The inspectors identified that
the licensee failed to repair the 2/3 cribhouse sump pumps level switches, in
accordance with the work control process, when the switches failed in February 2005.
This represented one inspection sample.
a. Effectiveness of Problem Identification
(1) Inspection Scope
The inspectors reviewed IR 331423 and the associated investigation report to verify that
the licensees identification of the problems were complete, accurate, and timely, and
that the consideration of extent of condition review, generic implications, and common
cause was adequate.
(2) Issues
There were no issues in the area of Effectiveness of Problem Identification.
b. Prioritization and Evaluation of Issues
(1) Inspection Scope
The inspectors reviewed IR 331423 and the associated investigation report. The
inspectors considered the licensees evaluation and disposition of performance issues,
and application of risk insights for prioritization of issues.
(2) Issues
The inspectors interviewed station personnel and reviewed the appropriate WO for the
issue. The inspectors noted that in February 2005, the 2/3 cribhouse sump was about
to overflow due to the failure of the sump pumps level switches. A facility type WO was
initiated in February to repair the level switches and was prioritized as a B3 ticket. Per
work control procedure WC-AA-106, Work screening and processing, Revision 2, B3
type work was supposed to be performed within five weeks.
The WO was initially on hold due to a request for parts; however, the work was not
completed even after the part arrived on March 1, 2005. The inspectors questioned the
lack of timely corrective actions for repairing the level switches, which were not
completed until May 2005. The licensee indicated that the untimely repair of the level
switches was because the work was assigned to the Fix It Now team. Due to emergent
work and maintenance outages which added to the teams backlog, the Fix It Now team
did not work this WO within the five week period. As a result of the licensees failure to
resolve the deficiency with the sump pumps level switches in February 2005, the
switches failed again and flooded the 2/3 cribhouse in May 2005. At that time, the
licensee initiated aggressive actions to repair the level switches. If the licensee had
repaired the switches in a more timely manner, reccurrence of the sump pumps failure
to run would not have occurred and caused the flooding in the cribhouse. The licensee
initiated IR 337135 to address the inspectors concerns. In addition, the licensee
24 Enclosure
implemented actions to address weaknesses in prioritizing the Fix It Now teams WO
backlog.
c. Effectiveness of Corrective Actions
(1) Inspection Scope
The inspectors reviewed the corrective actions which resulted from the investigation
report associated with IR 331423 to determine if the issue report addressed generic
implications and that corrective actions were appropriately focused to correct the
problem.
(2) Issues
There were no issues in the area of Effectiveness of Corrective Actions.
.5 Corrective Action Program
Introduction
The inspectors identified several examples where the licensee failed to properly
implement the various aspects of the stations CAP during this period. During the first
quarter 2005 and the fourth quarter of 2004, the licensee experienced problems with
writing issue reports. Initially, the inspectors planned to document this problem in the
first quarter inspection report; but, instead discussed this problem as an observation
during the quarterly exit meeting on April 15, 2005.
Additional examples of this problem ,as well as other deficient implementation aspects
of the stations CAP, continued to occur and included the lack of appropriate challenge
of documented information in issue reports, inappropriate closure of issue reports by the
site ownership committee (SOC) and management review committee(MRC), and the
failure of shift managers to document the operability basis when issue reports
documented known deficient plant conditions.
a. Effectiveness of Problem Identification
(1) Inspection Scope
The inspectors reviewed all the IRs and the associated immediate followup actions to
verify that the licensees identification of the problems was complete and accurate, and
that the consideration of extent of condition review, generic implications, and common
cause was adequate.
(2) Issues
Generally, the licensee identified deficient plant conditions but did not always enter the
items into the stations CAP. The licensee failed to generate five issue reports, until
prompted the inspectors. The issues were minor in nature. The licensee subsequently
generated the following Irs: 321457(Delay in Reset of TIP Group 2 Isolation from Partial
25 Enclosure
Group 2 Isolation), 333251(Ultrasonic Flow Meter for U2 Hydrogen Seal Oil Flow),
325867 (PPE Exemption Form not Properly Displayed), 345612 (Unit 2 SW Rad Monitor
Spike), and 338026 (Received Unexpected H2 Area Trouble Alarm).
b. Prioritization and Evaluation of Issues
(1) Inspection Scope
The inspectors considered the licensees evaluation and disposition of performance
issues, and application of risk insights for prioritization of issues.
(2) Issues
Generally the license prioritized and evaluated the issues. However, there were several
examples where either the shift manager failed to document the basis for operability for
deficient plant equipment or the site ownership and management review committees did
not challenge the absence of operability information or other information which ensured
effectiveness of the corrective action process. The oversight by the (CAP) committees
and the shift managers did not result in the inoperability of any equipment. The licensee
subsequently generated IRs 343019 (Operator Struck in Head by Falling Light Diffuser),
333408 (NRC Identifies Valve Locking Chain on Cable Tray Support), and 327336 (NRC
Questions Actions Taken in SOC and MRC Closure of IRs).
c. Effectiveness of Corrective Actions
(1) Inspection Scope
The inspectors reviewed the corrective actions for the associated IRs to determine if the
issue reports addressed generic implications and that corrective actions were
appropriately focused to correct the problem.
(2) Issues
The licensee continued to experience problems with initiating IRs without being
prompted by the inspectors. The site ownership and management review committees
had several instances where both groups were not effective in ensuring the appropriate
actions were taken by the station for documented plant deficiencies. Also, the shift
managers had not been consistently documenting the basis for why equipment
remained operable when deficiencies were identified with equipment.
This represented one inspection sample.
26 Enclosure
.6 Removal of the 2D Traversing Incore Probe Drawer While Clearance Order Danger Tag
Was Attached to Equipment
a. Inspection Scope
The inspectors reviewed the licensees followup actions to a clearance order event on
May 2, 2005. The inspectors interviewed several maintenance supervisors and
reviewed associated documentation for this event.
This represented one inspection sample.
b. Findings
Introduction: A Green finding was identified by the inspectors. The licensee failed to
identify that corrective actions were ineffective from a previous 2004 event involving the
failure to follow the clearance order process. Also, an instrument maintenance
technician failed to properly implement annual clearance order process training. As a
result, the instrument maintenance technician removed the 2D TIP drawer while it was
tagged out-of-service with a danger tag.
Description: On May 2, 2005, instrument maintenance (IM) technicians were assigned
to perform WO 692871-01 which was a two year preventive maintenance task on the 2D
TIP drawer. Operations personnel had placed clearance order #35879 to allow the
performance of other work associated with the system; a clearance order danger tag
was placed on the control switch of the 2D TIP drawer. During the pre-job brief, the IM
technicians did not discuss clearance order tags for WO 692871-01 because a
clearance order was not required for this type of work. After obtaining approval from the
on shift operations crew, the IM technician noted the clearance order danger tag on the
control switch of the 2D TIP drawer. Although the IM technicians pre-job briefing did
not discuss the 2D TIP drawer having a clearance order tag, the lead IM technician did
not question this information. Instead, the IM technician removed the drawer with the
clearance order tag and placed the tag inside the WO.
After the lead IM technician completed the work and was returning the 2D TIP drawer to
the control room on May 3, 2005, the Unit 2 unit supervisor noted the clearance order
danger tag inside the WO. The licensee re-installed the 2D TIP drawer, re-hung the
clearance order tag, and initiated a quick human performance investigation (QHPI). The
licensees investigation determined that of the two IM technicians conducting the work;
only the lead IM technician had been aware of the clearance order danger tag. The
second IM technician, who was responsible for only performing a verification that the
correct drawer was identified for removal, did not notice the danger tag. The lead IM
technician was not aware of the requirements specified in Clearance and Tagging
Procedure, OP-MW-109-101, Revision 3, which prohibited the removal of a component
from a system when the component had a danger tag attached to it. The IM lead
technician assumed that the system was in a safer condition by removing the drawer. In
addressing this issue, the licensee briefed this event to all maintenance personnel and
added more detailed training on the clearance order process to the annual Nuclear-
General Employee Training.
27 Enclosure
After the inspectors became aware of this issue, the inspectors informed the licensee
that this potentially significant personnel safety event did not receive the appropriate
level of concern and communication from the senior plant management. This issue was
not discussed at the operations shift turnover or the plan-of-the-day meetings. Also,
after the inspectors review of the QHPI, the inspectors determined that this event was a
repeat occurrence of an event on Unit 3 during the October 2004 refueling outage. The
QHPI failed to identify that this was a repeat event and that the corrective actions were
ineffective in preventing the recurrence of the May 2005 clearance order error. During
the previous event on November 4, 2004, an electrician removed the 3B drywell cooler
breaker which had been tagged out-of-service with a danger tag attached and in the
racked to test position. The licensee had also conducted a QHPI for this event and
implemented corrective actions which were limited to briefing electrical maintenance
personnel on the event. Since the second QHPI failed to identify ineffective corrective
actions from the first QHPI which also involved a clearance order error and both could
have had significant personnel safety consequences, the inspectors questioned the
appropriateness of conducting a QHPI for this type of event. Also, the inspectors were
concerned that the boilerplate QHPI did not contain the required information to ensure
previous events were reviewed while performing the QHPI. This was a concern to the
inspectors because no other actions were planned by the licensee other than the
performance of the QHPI, which would result in not discovering previous ineffective
corrective actions. The licensee generated IR 346783, as a result of the inspectors
comments on the deficient aspects of the QHPI. In addition, the licensee briefed this
event to all maintenance personnel and will conduct more detailed training on the
clearance order process during annual site training.
Analysis: The inspectors determined that the licensees failure to implement effective
corrective actions from the November 2004 event and an IM technicians failure to apply
annual clearance order training resulting in the repeat occurrence in May 2005
constituted a performance deficiency warranting a significance evaluation. The
inspectors concluded that the finding was greater than minor in accordance with
IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, issued
on May 19, 2005. The inspectors concluded that the finding, if left uncorrected, would
become a more significant safety concern by resulting in significant personnel safety
consequences, and because it impacted the barrier integrity cornerstone objective to
provide reasonable assurance that physical design barriers protect the public from
radionuclide releases caused by accidents or events. The primary cause of this finding
was related to the cross-cutting areas of problem identification and resolution as well as
human performance.
The inspectors completed a Phase 1 significance determination of this issue using
IMC 0609, Significance Determination Process, Appendix A, Attachment 1, dated
December 1, 2004. The inspectors concluded that the finding impacted the barrier
integrity cornerstone. Removal and re-installation of the 2D TIP drawer did not
adversely affect the ability to ensure containment isolation using the ball check
containment isolation valve. The inspectors answered Yes to question 1 under the B
containment barrier cornerstone column, in that, the finding ultimately did not adversely
affect containment isolation ability; and concluded that this issue was of very low safety
significance (Green).
28 Enclosure
Enforcement: No violations of NRC requirements occurred because the finding involved
non-safety related equipment. The licensee entered this issue into their corrective
program as IR 346783. The licensee briefed this issue to all three maintenance shops
and revised the annual Nuclear General Employee Training to include more detailed
discussions on the clearance order process. (FIN 05000237/2005008-03)
4OA3 Event Follow-up (71153)
.1 (Closed) URI 05000249/2005003-01: Install U3 Core Spray Lower Sectional
Replacement
b. Findings
Introduction: A Green finding involving a Non-Cited Violation of 10 CFR 50, Appendix B,
Criterion XI, Test Control, and Criterion III, Design Control., was identified by the
inspectors. The licensee failed to perform post-modification testing and to assure
critical aspects of the core spray modification installation, which included obtaining gap
measurement for mechanical joints, verifying the capability of the tooling to produce the
required surface finishes on pre-fabricated components, and verifying that the pre-
fabricated components were properly machined, met the leakage analysis
specifications.
Description: During the Fall 2004 Unit 3 refueling outage, the licensee implemented
engineering change 6602 for the replacement of the lower sectional piping of the core
spray system. The modification was intended to replace piping inside the reactor vessel
annulus that was susceptible to intergranular stress corrosion cracking (IGSCC) due to
the environment and original welded materials (Type 304 stainless steel). The IGSCC
could result in leakage from the piping into the annulus rendering the core spray system
inoperable. The lower sectional replacement was designed by General Electric (GE)
using IGSCC resistant materials with mechanical connections in lieu of eight previously
welded connections to further mitigate susceptibility to IGSCC.
The modification consisted of cutting the core spray piping in the annulus at two points.
The first, on a vertical section of pipe referred to as the downcomer area, and the
second after the piping turned horizontal at the point where the piping enters the core
shroud. This section, once cut out, would be replaced with an L shaped pre-fabricated
piece of piping made of IGSCC resistant materials previously mentioned. The
downcomer piping would be joined to the pre-fabricated piping using a compression
fitting. After being cut, the downcomer was made up to a pre-fabricated ring such that
there was a flat surface to surface contact. The bottom of the ring was rounded and
mated with the flanged area of the pre-fabricated piping. The other end of the pre-
fabricated piping was bolted to the core shroud.
General Electric performed GENE-0000-0021-4342-04, Dresden Nuclear Power
Station, Unit 3 Core Spray Line Lower Sectional Replacement Leakage Analysis,
Revision 0. This analysis calculated the maximum gap sizes where mechanical
components were joined together that would result in excess leakage outside the core
shroud. Potential leakage pathways were between the downcomer pipe and the ring,
between the ring and the flange, and between the pre-fabricated piping and the core
29 Enclosure
shroud. An important component to the leakage analysis was the surface finishes of the
cut piping and the pre-fabricated ring and flange. Exceeding the maximum gap size,
described in the leakage analysis, could render one or more trains of the core spray
system inoperable. Although these finishes were critical parameters in the modification,
the licensee did not verify that the modification was bounded by the leakage analysis
through the verification of maximum gap sizes or through post modification testing.
Since the licensee did not obtain these gap measurements, the inspectors requested
the licensee to demonstrate how they ensured that the maximum gaps were not
exceeded. The licensee was unable to provide documentation of compliance; however,
the licensee along with GE demonstrated how the design of the mating surfaces
between the pre-fabricated piping and the core shroud would ensure that the gap at that
location would not be exceeded.
The licensee requested documentation from GE showing that the tooling used to make
the piping cuts inside the reactor vessel annulus on the downcomer was capable of
producing the surface finish specified in the GE leakage analysis. General Electric did
not have any documentation that could demonstrate this capability at the time of the
request. General Electric sent two coupons, that had been cut by the tooling used at
Dresden, out for independent measurement. One of the two coupons did not meet the
surface finish specification requirements and was due to dropping of the coupon after it
had been cut at the site in San Jose, California. This action marred its finish and
caused it to fail the test. The inspectors concurred with GEs conclusion of why the
coupon failed after reviewing the applicable documentation.
The licensee requested that GE provide documentation to show that the pre-fabricated
components were machined to the specifications described in the leakage analysis.
Although documents were located, GE determined that the pre-fabricated ring did not
meet the leakage analysis specifications. Subsequently, GE determined that the
leakage analysis was still bounded by the new surface of the ring under GENE-0000-
0021-4342-04, Dresden Nuclear Power Station, Unit 3 Core Spray Line Lower Sectional
Replacement, Revision 3.
Although the licensee failed to perform a post modification test or obtain gap
measurements of the mechanical joints to ensure the modification was bounded by the
leakage analysis, the licensee was able to demonstrate, with the assistance of GE that
there was reasonable assurance that the modification was installed properly and that the
maximum leakage specifications were not exceeded.
One of the station procedures that implemented Exelon Quality Assurance Manual,
Topical Report, Revision 75, Chapter 11, was CC-AA-107-1001, Post Modification
Acceptance Testing, Revision 0. Step 4.2.3.5 of CC-AA-107-1001, stated that, there
are times when portions of the modification will not be tested or are unable to be tested.
Justification for not testing at the site needs to be provided. The licensee stated that
justification for not testing was never completed. The inspectors pointed out that
CC-AA-107-1001 allowed for not testing modifications; however, the Exelon Quality
Assurance Manual Topical Report did not. The inspectors determined by review of
IR 343848, and through discussions with licensee management that the licensee
planned to revise CC-AA-107, Configuration Change Acceptance Testing Criteria,
30 Enclosure
and/or CC-AA-107-1001. The procedure change would provide that the substitution for
post modification testing would ensure quality at least equivalent to that specified in the
original design bases. In addition, the licensee planned to confirm that the installed core
spray modification had been installed with a level of quality equivalent to the original
design basis.
Analysis: The licensee failed to perform post-modification testing and to assure critical
aspects of the core spray modification installation, which included obtaining gap
measurement for mechanical joints, verifying the capability of the tooling to produce the
required surface finishes on pre-fabricated components, and verifying that the pre-
fabricated components were properly machined, met the leakage analysis specifications
was a performance deficiency warranting a significance evaluation. The inspectors
concluded that the finding was greater than minor in accordance with IMC 0612, Power
Reactor Inspection Reports, Appendix B, Issue Screening, issued on May 19, 2005
because it affected the mitigating systems cornerstone objective of ensuring the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences, specifically the design control attribute. The
licensee, with assistance from GE was able to demonstrate proper installation of the
core spray system piping modification inspite of the licensees failure to ensure gap
measurements for mechanical joints, verify the capability of the tooling, determine that
the pre-fabricated components were properly machined, and conduct post modification
testing to ensure the leakage analysis remained valid for these various aspects.
The inspectors completed a Phase 1 significance determination of this issue using
IMC 0609, Significance Determination Process, Appendix A, dated December 1, 2004.
The inspectors determined that this finding impacted the mitigating system cornerstone.
The inspectors entered the mitigating systems cornerstone column of the Phase I SDP
sheet and answered No to all five questions. Therefore, the inspectors concluded that
the finding was of very low safety significance (Green).
Enforcement: Title 10 of the Code of Federal Regulations Part 50, Appendix B,
Criterion XI, states, a test program shall be established to assure that all testing
required to demonstrate that structures, systems, and components will perform
satisfactorily in service is identified and performed in accordance with written test
procedures which incorporate the requirements and acceptance limits contained in
applicable design documents. The test program shall include ... operational tests during
nuclear power plant operation, of structures, systems, and components.
The Exelon Quality Assurance Manual, Topical Report, Revision 75, Chapter 11, Test
Control implements Title 10 of the Code of Federal Regulations Part 50, Appendix B,
Criterion XI. The Exelon Quality Assurance Manual, Topical Report, Revision 75, states
in Chapter 11, Test Control, Section 2.1.1, that the test program covers all required tests
including the demonstration of satisfactory performance following plant maintenance or
modifications. Section 2.7 states, in part, The Company performs testing following
plant modification or significant changes in operating procedures to confirm that the
modification or changes produces the expected results.
Title 10 of the Code of Federal Regulations Part 50, Appendix B, Criterion III, Design
Control, states in part, that measures shall be established to assure that applicable
31 Enclosure
regulatory requirements and the design basis, as defined in § 50.2 and as specified in
the license application, for those structures, systems, and components to which this
appendix applies are correctly translated into specifications, drawings, procedures, and
instructions. These measures shall include provisions to assure that appropriate quality
standards are specified and included in design documents and that deviations from such
standards are controlled.
Contrary to the above, from October 26, 2004, to December 11, 2004, the licensee
installed Modification EC 6602, Core Spray Lower Sectional Replacement, without
performing post modification testing or assuring that appropriate quality standards were
specified in installation procedures and instructions to ensure obtaining gap
measurement for mechanical joints, verifying the capability of the tooling to produce the
required surface finishes on pre-fabricated components, and verifying that the pre-
fabricated components were properly machined in order to meet the leakage analysis
specifications. Because this violation was of very low safety significance and because
the issue was entered into the licensees corrective action program (IR 303093,
IR 325097, and IR 325133), the issue is being treated as a NCV, consistent with Section
VI.A.1 of the NRC Enforcement Policy. (NCV 05000249/2005008-04)
.2 (Closed) Licensee Event Report (LER) 50-237/2005-002-00: Unit 2 Group 1 Isolation
and Resulting Scram
On March 24, 2005, with Unit 2 at full power, an automatic scram occurred due to the
malfunction of the A electro-hydraulic control system pressure regulator. All systems
responded as expected to the scram. Initial investigation and troubleshooting activities
by the licensee focused on the pressure regulator circuitry and card connections that
could have caused the transient. However, no abnormalities were identified. In
addition, the licensee sent the A45", C46", and A54" cards from the A electro-
hydraulic control pressure regulator circuitry to an offsite lab for failure analysis. No
abnormalities or failed components were found.
A root cause investigation to determine the cause of the failure was initiated and
concluded that the apparent cause of the failure was indeterminate. The licensee
determined that the most probable cause of this event was attributed to an increase in
electrical resistance between electrical pins 13 and 22 on card A54." Also, calculations
identified that an increase in electrical resistance of approximately 220 ohms for pin 22
or 2000 ohms for pin 13 could have caused the event. Corrective actions completed
and planned by the licensee included the replacement of the A45", A54", and C46"
cards prior to startup; replacement of the A54" card backplane connector; and rework
of the remaining connectors to card A54" during the Fall 2005 refueling outage. This
LER was reviewed by the inspectors and no findings were identified. This LER is
closed.
.3 (Closed) LER 50-249/2004-005-00: Unit 3 Isolation Condenser Time Delay Relays
Exceed Technical Specification Allowable Value
32 Enclosure
b. Findings
Introduction: A Green finding involving a Non-Cited Violation of 10 CFR Part 50,
Appendix B, Criterion XVI, was identified by the inspectors. The licensee failed to
implement adequate corrective actions to prevent recurrence of a deficient condition that
occurred on September 6, 1996, which involved surveillance testing of the anticipated
transient without scram (ATWS) time delay relays. This failure caused the Unit 3
isolation condenser (IC) time delay relays to exceed their TS allowable values due to the
continued usage of the stopwatch as a calibration tool.
Description: On September 29, 2004, the licensee conducted DIS 1300-08, Sustained
High Reactor Pressure Time Delay Relay Calibration, Revision 2. Three of the four
reactor high pressure IC initiation time delay relays were found out-of-tolerance and in
non-compliance with TS requirements. The IC will initiate on a sustained high reactor
pressure in a one-out-of-two twice logic. The purpose of the time delay was to avoid
spurious initiations of the IC system by allowing time for the spurious pressure spike,
caused by a main steam isolation or stop valve closure, to decay. The maximum time
delay allowed per TS surveillance requirement 3.3.5.2.3 was 15 seconds. The as-found
time delay relay setting values for high pressure switches 2-263-53A, 53B and 53C were
15.2, 15.8 and 15.1 seconds, respectively. IR 258172 was issued on
September 29, 2004, to document this issue.
The inspectors had previously closed LER 50-249/96012-00, which discussed the out of
tolerance of ATWS time delay relays, due to inadequate calibration check methodology.
Three of the four low-low reactor water level ATWS time delay relays were found
outside of the TS tolerance. The licensee determined that the initial failures were
attributable to human error in using a stopwatch. In addressing this issue, the licensee
switched to the use of a chart recorder to enhance time delay measurements. The
licensee indicated that the testing methodology, that utilized the chart recorder, would
produce more reliable and accurate results by eliminating human errors and reducing
test equipment response time errors.
One of the corrective actions associated with the 1996 event was to revise safety related
surveillance procedures to either increase the available margin to the TS allowable value
and/or require the use of a measurement technique that was not affected by errors
inherent in the use of stopwatches. A stopwatch was determined to be insensitive to
calibration checks on components with limited margin. However, the IC time delay
relays were not identified as affected components; therefore, the procedure was not
revised.
The three relays that were outside the TS allowable value were last tested on
June 16, 2002, using DIS 1300-01, Sustained High Reactor Pressure Time Delay Relay
Calibration, Revision 15. The relays were left within the as-left setting tolerance using a
stopwatch. As a result, when the relays were tested on September 29, 2004, the
as-found values for three of the relays were outside the TS limit which was a violation of
the TS.
Analysis: The inspectors determined that the failure to have adequate corrective actions
associated with repetitive failures of safety-related instruments was a performance
33 Enclosure
deficiency warranting a significance evaluation. The inspectors concluded that the
finding was greater than minor in accordance with IMC 0612, Power Reactor Inspection
Reports, Appendix B, Issue Screening, issued on May 19, 2005, because it impacted
the mitigating system cornerstone objective to ensure availability, reliability, and
capability of systems that respond to initiating events and because it affected the
reliability of a safety related component. The failure to utilize appropriate tools while
performing instrument calibrations can result in equipment being outside of the TS
allowable limits over the surveillance period and hence inadequate performance of
safety related equipment. However, the IC system did not lose the ability to perform its
safety function and all other mitigating systems were available. Therefore, this finding
was considered to be of very low safety significance. The licensee was able to
demonstrate, with the assistance of outside vendors, that during the period since the
last calibration of the time delay relays, the IC system would have initiated at a time
sooner than that assumed in the loss of feedwater transient analysis which was the
most bounding analysis. The primary cause of this finding was related to the cross-
cutting issue of problem identification and resolution.
The inspectors completed a Phase 1 significance determination of this issue using
IMC 0609, Significance Determination Process, Appendix A, Attachment 1, dated
December 1, 2004. The inspectors concluded that the finding impacted the mitigating
system cornerstone. The inspectors answered No to all five questions under the
mitigating system cornerstone column, and the issue screened as having very low safety
significance (Green).
Enforcement: Appendix B, Criterion XVI of 10 CFR Part 50, required, in part, that
measures shall be established to assure that conditions adverse to quality, such as
failures, malfunctions, deficiencies, deviations, defective material and equipment, and
non-conformances are promptly identified and corrected. In the case of significant
conditions adverse to quality, the measures shall assure that the cause of the condition
is determined and corrective actions taken to preclude repetition. Contrary to the above,
the licensee implemented ineffective corrective actions to prevent recurrence of the
1996 event, involving out-of-tolerances of ATWS relays. This failure allowed the usage
of stopwatches in the performance of safety related surveillances. As a result three
relays were outside TS requirements after performing DIS 1300-01, Revision 15. As a
result of the 2004 event, the licensee initiated IR 258172, created an action item to
review the root cause of the event, revised the IC initiation time delay relay calibration
procedure to require the use of a strip chart recorder, and created an action item to
evaluate the extent of condition. Because this violation was of very low safety
significance and it was entered into the licensees corrective action program
(IR 258172), this violation is being treated as an NCV, consistent with Section VI.A of
the NRC Enforcement Policy. (NCV 05000249/2005008-05)
4OA4 Cross-Cutting Findings
.1 A finding described in Section 4OA2.3(1) of this report had, as its primary cause, a
problem identification and resolution issue, in that, the licensee was slow in identifying a
failed damper in the reactor building ventilation system. As a result, a design deficiency
with the standby gas treatment system, that caused a delay in the systems ability to
restore secondary containment to the required -0.25 inch differential pressure, continued
34 Enclosure
to exist. The design deficiency had existed since original construction and remained
masked by the damper failure until 2005.
.2 A finding described in 4OA2.3(4) of this report had, as its primary cause, problem
identification and resolution as well as human performance, in that, the licensee failed to
implement effective corrective actions for a November 2004 event involving the removal
of equipment with a clearance order danger tag. As a result, a repeat event involving
an instrument maintenance technician removing equipment with a clearance order
danger tag occurred in May 2005. The instrument maintenance technician had received
training on the clearance order process and should have been aware of the requirement
that prohibited the removal of equipment when tagged in this manner.
.3 A finding described in Section 4OA3.3 of this report had, as its primary cause, problem
identification and resolution. The licensee failed to implement adequate corrective
actions to prevent recurrence of a deficient condition that occurred on
September 6, 1996, which involved surveillance testing of ATWS time delay relays.
This failure caused the Unit 3 isolation condenser time delay relays to exceed the TS
allowable values due to the continued usage of a stopwatch as a calibration tool.
4OA5 Other Activities
.1 Operational Readiness of Offsite Power (Temporary Instruction (TI) 2515/163)
The objective of TI 2515/163, "Operational Readiness of Offsite Power," was to confirm,
through inspections and interviews, the operational readiness of offsite power (OSP)
systems in accordance with NRC requirements. On May 22-25, 2005, the inspectors
reviewed licensee procedures and discuss the attributes identified in TI 2515/163 with
licensee personnel. In accordance with the requirements of TI 2515/163, inspectors
evaluated licensee procedures against the attributes discussed below.
The operating procedures that the control room operator uses to assure the operability
of the OSP have the following attributes:
1. Identify the required control room operator actions to take when notified by the
transmission system operator (TSO) that post-trip voltage of the OSP at the
nuclear power plant will not be acceptable to assure the continued operation of
the safety-related loads without transferring to the onsite power supply.
2. Identify the compensatory actions the control room operator is required to
perform if the TSO is not able to predict the post-trip voltage at the nuclear
power plant for the current grid conditions.
3. Identify the notifications required by 10 CFR 50.72 for an inoperable offsite
power system when the nuclear station is either informed by its TSO or when an
actual degraded voltage condition is identified.
The procedures to ensure compliance with 10 CFR 50.65(a)(4) have the following
attributes:
35 Enclosure
1. Direct the plant staff to perform grid reliability evaluations as part of the required
maintenance risk assessment before taking a risk-significant piece of equipment
out-of-service to do maintenance activities.
2. Direct the plant staff to ensure that the current status of the OSP system has
been included in the risk management actions and compensatory actions to
reduce the risk when performing risk-significant maintenance activities or when
loss of offsite power or station blackout mitigating equipment are taken
out-of-service.
3. Direct the control room staff to address degrading grid conditions that may
emerge during a maintenance activity.
4. Direct the plant staff to notify the TSO of risk changes that emerge during
ongoing maintenance at the nuclear power plant.
The procedures to ensure compliance with 10 CFR 50.63 have the following attribute:
1. Direct the control room operators on the steps to be taken to try to recover offsite
power within the station blackout coping time.
The results of the inspectors' review were forwarded to office of Nuclear Reactor
Regulation for further review and evaluation. "
.2 Operation of an Independent Spent Fuel Storage Installation (ISFSI) (60855.1)
a. Inspection Scope
The inspectors evaluated the licensees response to the failure of the cask transfer
facility (CTF) while the CTF was lifting a cask loaded with fuel. The inspectors reviewed
the prompt investigation report, a condition report, and an engineering evaluation
associated with the incident. The inspectors also reviewed the certificate of compliance
(CoC), the technical specifications, the Safety Evaluation Report, Revision 1, the Final
Safety Analysis Report (FSAR), Revision 2, and the Calculation Package On Hitran-140,
Revision 2. The purpose of the review was to verify that the cask configuration had
been analyzed to withstand natural phenomena such as tornados, earthquake, tornado
missile strike, and a vertical drop, and that the radiation dose rates contained in the
technical specifications were not exceeded. The inspectors also reviewed the
10 CFR 72.48 safety screening/evaluation and the special procedure, Hi-Track setdown
at the CTF (Action Tracking Item (ATI) 340904-14), to verify that the use of an
alternative lifting device with four hydraulic lifting boom systems conformed with
conditions of the CoC , the technical specifications, and the FSAR.
b. Findings
No findings of significance were identified
36 Enclosure
4OA6 Meetings
.1 Interim Exit Meeting
Interim exit meetings were conducted for:
- Maintenance Effectiveness Periodic Evaluation with D. Bost, Site Vice President
on April 15, 2005;
- Radiation Protection (RETS/ODCM) inspection with Mr. D. Bost and other
licensee staff on April 29, 2005;
- Licensed Operator Requalification 71111.11 with Mr. M. Otten, Operations
Requalification Training Supervisor on June 16, 2005, via telephone; and
- Independent Spent Fuel Storage Installation with Mr. M. Mikota, Dry Cask
Project Manager, via telephone, on June 21, 2005.
ATTACHMENT: SUPPLEMENTAL INFORMATION
37 Enclosure
KEY POINTS OF CONTACT
Licensee
D. Bost, Site Vice President
D. Wozniak, Plant Manager
S. Bell, Shipping Specialist
H. Bush, Radiological Engineering Manager
R. Conklin, Radiation Protection Supervisor
J. Fox, Design Engineer
R. Gadbois, Operations Director
D. Galanis, Design Engineering Manager
V. Gengler, Dresden Site Security Director
J. Griffin, Regulatory Assurance - NRC Coordinator
P. Salas, Regulatory Assurance Manager
J. Kalb, Environmental/ODCM Chemist
A. Khanifar, Nuclear Oversight Director
S. Kroma, Reactor Services Project Manager
T. Loch, Supervisor, Design Engineering
M. McGivern, System Engineer
M. Mikota, Dry Cask Project Manager, Dresden
D. Moore, Dry Cask Project Manager, Quad Cities
D. Nestle, Radiation Protection Technical Manager
M. Otten, Operations Requalification Training Supervisor
M. Overstreet, Radiation Protection Supervisor
R. Quick, Security Manager
N. Spooner, Site Maintenance Rule Coordinator
J. Strmec, Chemistry Manager
B. Surges, Operations Requalification Training Supervisor
G. Bockholdt, Maintenance Director
S. Taylor, Radiation Protection Director
NRC
M. Ring, Chief, Division of Reactor Projects, Branch 1
R. Zuffa, Resident Inspector Section Head, Illinois Emergency Management Agency
R. Schulz, Illinois Emergency Management Agency
1 Attachment
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000237/2005008-01 URI Inability to Trip the 2B Service Water Pump from the
Control Room
05000237/2005008-02 FIN Failure of the Refuel Floor Damper & Design Deficiency
05000249/2005008-02 with the Standby Gas Treatment System
05000237/2005008-03 FIN Removal of the 2D Traversing Incore Probe Drawer With
Clearance Order Danger Tag Attached
05000249/2005008-04 NCV Modification to the Unit 3 Core Spray Piping
05000249/2005008-05 NCV Isolation Condenser Time Delay Relays Exceed TS Value
Closed
05000237/2005008-02 FIN Failure of the Refuel Floor Damper & Design Deficiency
05000249/2005008-02 with the Standby Gas Treatment System
05000237/2005008-03 FIN Removal of the 2D Traversing Incore Probe Drawer With
Clearance Order Danger Tag Attached
05000249/2005008-04 NCV Modification to the Unit 3 Core Spray Piping
05000249/2005008-05 NCV Isolation Condenser Time Delay Relays Exceed TS Value
(4OA3.4)05000249/2005003-01 URI Install U3 Core Spray Lower Sectional Replacement
50-249/2004-005-00 LER Unit 3 Isolation Condenser Time Delay Relays Exceed
Technical Specification Allowable Value
50-237/2005-002-00 LER Unit 2 Group 1 Isolation and Resulting Scram
Discussed
None
2 Attachment
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection. Inclusion on this list does
not imply that the NRC inspectors reviewed the documents in their entirety but rather that
selected sections of portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
1R04 Equipment Alignment
-DOP 6900-E4; Revision 11; Unit 2 Electrical Systems Checklist
-DOP 6900-E1; Revision 07; Unit 3 Electrical Systems Checklist
-DOP 7500-M1/E1; Revision 06; Unit 2/3 Standby Gas Treatment
-OP-MW-109-101; Revision 2, Attachment 14; Worker Tagout Form Part 1: Hang/Lift
Section; Tagout # 2005-3131
-DOP 1400-M1; Revision 20; Unit 3 Core Spray System
-DOP 1400-E1; Revision 03; Unit 2 Core Spray Electrical
-DOP 1400-M1/E1; Revision 17; Unit 3 Core Spray System
-DOP 0900-E1; Revision 20; Unit 2(3) Control Room Panels
-DOP 1500-E1; Revision 13; Unit 3 LPCI and CCSW Electrical
-DOP 1500-M1; Revision 29; Unit 3 LPCI and Containment Cooling Valve Checklist
-DOP 1500-01; Revision 13; Preparation of Low Pressure Coolant Injection for
Automatic Start
-DOP 1500-02; Revision 50; Torus Water Cooling Mode of Low Pressure Coolant
Injection System
-DOP 1500-03; Revision 29; Containment Spray Cooling Mode of Low Pressure Coolant
Injection System
-DOP 1500-05; Revision 14; LPCI System Operation and/or Shutdown After Automatic
Initiation
-IR 344388; LPCI Thermal Performance Calculations Delayed; June 9, 2005
-IR 342659; Flow Transmitter Found Out of Tolerance During Calibration; June 9, 2005
-IR 314046; CCSW Pump Vibration in the Alert Range; March 17, 2005
-IR 295277/295464; Unit 3 CCSW Flow Instrumentation Piping Improperly Supported;
January 28, 2005
-IR 293713; Pipe Degradation of 2C & 2D CCSW Pump Discharge Elbows;
January 24, 2005
-DWG M-355; Diagram of Service Water Piping; Revision RP
-DWG M-360; Sheet 1; Diagram of L.P. Coolant Injection Piping; Revision VK
-DWG M-360; Sheet 2; Diagram of L.P. Coolant Injection Piping; Revision AV
1R05 Fire Protection
-Dresden Fire Pre-Plan U2TB-43; Revision 05
-Dresden Fire Pre-Plan U2TB-45; Revision 05
-Dresden Fire Pre-Plan U2TB-51; Revision 05
-Dresden Fire Pre-Plan U3TB-76; Revision 05
3 Attachment
-Dresden Fire Pre-Plan U2/3DG-105; Revision 05
-IR 328975; Low Water Level in Ssd Light Batteries; May 2, 2005
-IR 333918; Bell Alarm for 3 Detectors Only Buzzes; May 10, 2005
-IR 334382; Green Normal Power Light Is out Wih No Trouble or Alarm LIG;
May 12, 2005
-IR 336018; 1-4199-H-TV Leaks by the Seat; May 17, 2005
-IR 336146; 3-7902-396, BOP EM Light 396 Has Solid Fast Charge Light on;
May 18, 2005
-IR 336779; 2-7902-285, SSD Light Battery Requires Replacement; May 19, 2005
-IR 337075; Two NLOs Do Not Indicate Qualified in PQD; May 20, 2005
-IR 337139; Two NLSs Respirator Mask Med. Qualifications Were Not Met;
May 20, 2005
-IR 337503; Weaknesses for 2nd Quarter Fire Drill; May 23, 2005
-IR 338671; Dresden Fire Protection Report; May 26, 2005
1R06 Flooding
-IR 302902; 2/3 Cribhouse Sump Failure; February 18, 2005
-IR 331158; U2 west side ECCS Corner Room Watertight Door 1/2" Ajar; May 2, 2005
-IR 331423; 2/3 Cribhouse (UHS) Sump Pump Failure; May 3, 2005
-IR 331583; LS-3-4941-8 May Be Impacted by Temporary Staged Equipment;
May 3, 2005
-IR 333678; Shift Manager Fails to Generate PINV Assignment for Prompt; May 10,
2005
-IR 337100; NRC Questions Timeliness of 2/3 Cribhouse Sump Repairs; May 17, 2005
-IR 337105; Troubleshooting WO Documentation Incomplete; May 20, 2005
-IR 337135; NRC IDs FIN Backlog Issue; May 16, 2005
-IR 338392; SOC Enters Incorrect Information in IR; May 25, 2005
-WO 784571; 2/3 Cribhouse Sump Failure; February 23, 2005
-DOA 0040-02; Localized Flooding in Plant; Revision 15
-NRC Information Notice 2005-11; Internal Flooding / Spray-down of Safety Related
Equipment Due to Unsealed Equipment Hatch Floor Plugs and/or Blocked Floor Drains;
May 6, 2005
-WC-AA-106; Revision 2
1R07 Heat Sink
-IR 331949; Corrosion of Channel Head on RBCCW Heat Exchanger; May 4, 2005
-IR 332102; 2A TBCCW Heat Exchanger End Covers Are Degraded; May 5, 2005
-IR 332659; Maintenance Rule Database Incorrect; May 6, 2005
1R11 Operator Requalification
-IR 326406; Breaker Inspection Finds Trip Coil Incorrectly Mounted; April 19, 2005
-IR 330042; The Results of the FASA on LORT Exam Readiness - 4 Recom.;
April 29, 2005
-IR 334912; NOS Identifies Minor Exam Security Issue; May 13, 2005
4 Attachment
1R12 Maintenance Effectiveness
-IR 181118; Floor drains backed up in U2 HPCI contaminated floor space;
October 14, 2005
-IR 198770; HPCI Inoperable on Unit 2; February 1, 2004
-IR 198824; RBEDT pump down rate clos; February 1, 2004
-IR 201799; Failed Surveillance on U1 Battery Charger Swap; February 13, 2004
-IR 219445; CCSW Piping Degradation Exceeds Code Minimum; May 6, 2004
-IR 268340; Corporate PE FASA Procurement Engineering Assessment Plan;
February 24, 2005
-IR 270869; Received Alarm (923-4) D-1, 3B/D RBFD Sump PP Trip/Isol;
November 5, 2004
-IR 308487; Maintenance Rule Quarterly Evals Not Performed for Iso Cond.;
March 3, 2005
-IR 325977; Risk Tool Does Not Model RAT Breaker to Bus 34; April 18, 2005
-IR 327965; U2 CRD P-4 PMT Failed Due to Seat Leakage - Repeat Issue;
May 13, 2005
-IR 333736; Maint. Rule Database Support Documentation Needs Update;
May 10, 2005
-IR 334228; Maintenance Rule Functional Failure Criteria Needs to Be Eval;
May 11, 2005
-IR 336506; Maintenance Rule Evaluations Not Completed as Required; May 17, 2005
-ER-AA-310-1001; Maintenance Rule - Scoping; Revision 1
IR12 Maintenance Effectivenss (71111.12B)
-Maintenance Rule Periodic Assessment #5; October 1, 2002 - September 30, 2004;
dated December 2004
-Shutdown Cooling (a)(1) Action Plan; dated January 9, 2003
-Reactor Coolant Pressure Boundary (a)(1) Action Plan; dated December 18, 2003
-Secondary Containment (a)(1) Action Plan; dated May 22, 2003
-CCSW Supply to CR HVAC (a)(1) Action Plan; dated January 31, 2002
-Instrument Air (a)(1) Action Plan; dated January 20, 2005
-Augmented Primary Containment Vent (a)(1) Action Plan; dated July 16, 2004
-Feedwater Unit 2 (a)(1) Action Plan; dated January 22, 2004
-Service Water Standby Coolant Supply (a)(1) Action Plan; dated December 18, 2003
-List of Maintenance Rule Equipment Monitored for Unavailability; dated March, 2005
-List of Functional Failures for Assessment Period from October 1, 2002 -
September 30, 2004; dated October 2004
-Expert Panel Meeting Minutes; dated January 31, 2003
-Expert Panel Meeting Minutes; dated June 24, 2003
-Expert Panel Meeting Minutes; dated September 11, 2003
-Expert Panel Meeting Minutes; dated February 12, 2004
-Expert Panel Meeting Minutes; dated May 21, 2004
-Expert Panel Meeting Minutes; dated August 5, 2004
-HPCI System Health Overview Report; December 2004
-125 VDC System Health Overview Report; December 2004
-CCSW Quarterly Ship System Report; December 2004
-Primary Containment System Health Overview Report; December 2004
5 Attachment
-ER-AA-310; Implementation of the Maintenance Rule; Revision 3
-ER-AA-310-1003; Maintenance Rule - Performance Criteria Selection; Revision 2
-ER-AA-310-1004; Maintenance Rule - Performance Monitoring; Revision 2
-ER-AA-310-1005; Maintenance Rule - Dispositioning Between (a)(1) and (a)(2);
Revision 2
-ER-AA-310-1007; Maintenance Rule - Periodic (a)(3) Assessment; Revision 3
-MA-AA-716-210; Performance Centered Maintenance (PCM) Process; Revision 3
-MA-AS-716-210-1001; Performance Centered Maintenance Templates; dated
July 26, 2004
-SA-1126; Probability Risk Assessment Basis for Dresden Maintenance Rule
Availability, Performance Criteria and Revisions to Reliability Performance Criteria;
Revision 0
-Focused Area Self-assessment - Dresden Maintenance Rule Program (ATI
178673-01); dated October 1, 2003
1R13 Maintenance Risk Assessments and Emergent Work Control
-IR 333497; Inadequate Preparation Causes Schedule Delay; May 10, 2005
-IR 333822; HLAS Generated Within the Execution Week Without and IR; May 10, 2005
-IR 336144; Unit 3 125 Vdc Battery Discharge Test Stopped Prematurely; May 18, 2005
1R15 Operability Evaluations
-IR 324995; 2B Service Water Pump Breaker Failed to Trip from C/S; April 15, 2005
-IR 328459; Pipe Support for Line 2-3711-21/2" L is Damaged; April 25, 2005
-IR 328461; Feedwater Sparger End Bracket Pin Stops Are Loosening; April 25, 2005
-IR 329880; Ineffective CA Taken 3B Recirc Seal Hydro Failure in D3R18; April 28, 2005
-IR 333831; NOS Identifies OPS Not Following Guidance in LS-AA-120; May 10, 2005
-IR 336707; NRC & IEMA Req. For Additional Clarification for 50.50 Eval; May 19, 2005
-Operability Evaluation No.04-015
-EC No. 352592; Operability Evaluation for Isolation Condenser Steam Supply Vent
Lines 2-1309-3/4"- A, 2-1308-3/4"- A, and 2-1307-3/4"- A
-EC No. 353273; Modify U2 IsCo Steam Supply Vent Line Supports
-NES-MS-03.2; Revision 5; Evaluation of Discrepant Piping and Support Systems
-Specification K-4080; Revision 12; General Work Specification,
Maintenance/Modification Work
-USA Standard Code for Pressure Piping B31.1.0, Power Piping; 1967
-American Society of Mechanical Engineers Code,Section III, Division I; 1976
-Dresden UFSAR Sections 3.9.3.1.3.1.1 (Acceptance Criteria) and 5.4.6 (Isolation
Condenser)
1R16 Operator Work-Around
-OP-AA-102-103; Operator Work-Around Program; Revision 1
1R17 Permanent Plant Modification
-IR 303093; IEMA [Illinois Emergency Management Agency] Inspector Questions PMT
[Post Modification Testing] for Core Spray Modification; February 18, 2005
6 Attachment
-IR 325133; NRC Questions QATR [Quality Assurance Topical Report] Consistency
With CC [Configuration Change] Procedure; April 15, 2005
-IR 325097; EC [Engineering Change] 6602 Lacks Documented Justification for No PMT
[Post-Modification Testing]; April 15, 2005
-IR 330762; PMT for 2-1901-40 U2 FPC Filt Demin Byp AOV Mod Failed; May 24, 2005
-WO 97010448-06; Install Lower Sectional Replacement Piping as Required
-GENE-0000-0021-4342-04; Dresden Nuclear Power Station, Unit 3 Core Spray Line
Lower Sectional Replacement; Revision 0
-GENE-0000-0021-4342-04; Dresden Nuclear Power Station, Unit 3 Core Spray Line
Lower Sectional Replacement; Revision 1
-GENE-0000-0021-4342-04; Dresden Nuclear Power Station, Unit 3 Core Spray Line
Lower Sectional Replacement; Revision 3
-Field Deviation Disposition Request RMCN05077; Revision 0; dated October 8, 2004
-Terminal Manufacturing Company, Mechanical Measurements Inspection Report; Job
Number 11007- 1 & 2; dated April 1, 2005;
1R19 Post Maintenance Testing
-DOS 4400-01; Containment Cooling Service Water Vault Floor Drain; Revision 08
-DIS 3900-05; Diesel Generator Cooling Water Flow Indication Calibration; Revision 04
-DOS 6600-08; Diesel Generator Cooling Water Pump Quarterly and
Comprehensive/Progressive Test for Operational Readiness and In-Service Test (IST)
Program; Revision 32
-WO Package 00777955-01; D2/3 QTS TS D/G Cooling Water Pump Test for IST
Program Surveillance
-IR 324995; 2B Service Water Pump Breaker Failed to Trip from C/S; April 15, 2005
-IR 325097; EC 6602 Lacks Documented Justification for No PMT; May 5, 2005
-IR 329020; Perform and Document Extent of Condition Reviews 4KV BKR;
April 28, 2005
-IR 330004; D3M11 Forced Outage Due to 3B Rx. Recirc. Pp.seal Failure;
April 29, 2005
-IR 335891; RC EOC Discovered Another Recirc Seal Reverse Press Event;
May 17, 2005
-IR 329888; Initiate Root Cause for 3b Recirc Pump Seal Degradation; April 28, 2005
1R20 Outage Activities
-IR 324800; TR 29 Outage During D2R19 Requires Unit 3 Shutdown; April 14, 2005
-IR 329242; D3M11: Found Loose Hardware on 3E ERV Microswitch; May 24, 2005
-IR 329541; D3M11 Post-job Critique (OPS-Nightshift); April 28, 2005
-IR 330355; Equipment Status Tags Log Entry Report; May 11, 2005
-IR 331080; Limit Switch #1 for IRM#14 Drive Circuit Not Working; May 2, 2005
-IR 333410; Data Recorded in Incorrect ROWS on NF-AB-715 Attachment 2;
April 29, 2005
-IR 333418; Delays During U3 Startup Following D3M11; May 9, 2005
-IR 330503; NRC Identified Items During U3 Drywell Close Out, D3M11; April 30, 2005
-IR 330547; D3M11 Drywell Closeout Discrepancies; April 30, 2005
7 Attachment
1R22 Surveillance Testing
-IR 324377; Increase in U2 DW under Vessel Temp Points 24, 25, and 26;
April 15, 2005
-IR 324858; IR Not Written to Revise DIS 0263-01; April 14, 2005
-IR 329649; 2 of 8 MSIVs Timed Unsat During Surveillance; April 28, 2005
-IR 329880; Ineffective CA Taken 3B Recirc Seal Hydro Failure in D3R18; April 28, 2005
-IR 329904; Potential Error Occurred During D3R18 3B RR Motor Work; April 28, 2005
-IR 330844; 2-1349-B Iso. Condenser High Flow Ind/switch Out of Spec; May 2, 2005
-IR 332046; 3-1705-16B Fuel Ppol CH B Out of Tolerance; May 5, 2005
-IR 333412; No Feedback Ever Given on Negative Scorecards; May 9, 2005
-IR 335633; D2 Core Flow Found Outside Procedural Tolerance During CAL;
May 16, 2005
-IR 335776; Timing on Relay Was Found to Be out of Tolerance; May 17, 2005
-IR 335900; Unit 3 #14-51 Accum Pressure Switch Out-of-Tolerance; May 17, 2005
-IR 336123; D3 HCU Pressure Switch 30-19 Out of Tolerance; May 17, 2005
-IR 337554; Reset Operations Team Event Clock; May 23, 2005
-IR 338564; U1 125 VDC Battery Float Voltage Out of Tolerance; May 26, 2005
-IR 348496; U2 SBO Panel 2202-105 Alarm Tiles Not Functioning; June 29, 2005
-WO 00570002; D2 24M TS Div 1 LPCI Cont Cooling System Functional Test;
March 24, 2005
-DOS 6600-01; Diesel Generator Surveillance Tests; Revision 88
-DOS 6620-07; SBO 2 (3) Diesel Generator Surveillance Tests; Revision 18
-WO Package 00547472
-WO Package 00810022
-WO Package 00788502
-WO Package 00788507
-Unit NSO Daily Surveillance Log; Unit 2(3), Appendix A, Revision 98
1R23 Temporary Plant Modifications
-OP-AA-106-101-1006; Revision 1; Operational and Technical Decision Making Process
-CC-MW-112-1001; Training and Reference Material for Temporary Configuration
Changes
-Dresden FSAR 15.1.3; Increase in Steam Flow
-Dresden FSAR 15.1.3.2; Sequence of Events and System Operation
-Dresden FSAR 15.2; Decrease in Heat Removal by the Reactor Coolant System
-Dresden FSAR 15.2.1; Steam Pressure Regulator Malfunction
-Dresden FSAR 15.2.2.1; Load Rejection Without Bypass
-Dresden FSAR 15.2.3.1; Turbine Trip Without Bypass
-Drawing 12E-2910S; Schematic Diagram Electro-Hydraulic Control System Pressure
Control Unit; Revision B
-IR 330827; Temporary power cord usage; May 2, 2005
-IR 333103; LD has control of U2 output CB through SCADA; May 27, 2005
-IR 333454; DIS 0600-05 reactor narrow range level calibration; May 10, 2005
-IR 333797; Inappropriate revision to WO during D3M11; May 10, 2005
8 Attachment
2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems
-Offsite Dose Calculation Manual; Chapters 2, 4, and Appendix A (Revision 2),
Chapter 10 (Revision 4), Chapter 12 (Revision 5), and Appendix F (Revision 2)
-Dresden Nuclear Power Station Radioactive Effluent Release Reports for Calendar
Years 2002, 2003, and the 2004 Draft Report; dated April 30, 2003, April 30, 2004 and
Undated 2004 Draft Report, respectively
-CY-DR-170-2020/2030; Abnormal/Unmonitored Radiological Release; Revision 0
-Dresden Computation for Mn-54 Identified in Service Water Sample (DAR-2002-04);
dated April 7, 2003
-Radiation Protection Memorandum 99-001; Unit 1 Main Turbine Floor Effluents; dated
January 4, 1999
-DCP 3207-01; Gamma Isotopic Analysis; Revision 19
-DCP 2000-28; River Discharge; Revision 17
-CY-DR-120-600; Liquid Radwaste Scaling Factors; Revision 1
-CY-DR-170-210; Main Chimney Sampling; Revision 0
-Annual/Semi-Annual Surveillance Records of Unit 2/3 Radwaste High Radiation Area
Room Material Condition Inspections; 2004 through March 2005
-IR 00250661; Floor Drain and Waste Collector Tank Room Has Leaks;
September 7, 2004
-DIS-1700-14; Unit 2/3 Reactor Building Vent Stack SPING Calibration;
December 12, 2003
-DRS 5821-56; SPING Effluent Monitor Calibration; dated December 15, 2003
-DIS-1700-14; Unit 2/3 Main Chimney SPING Calibration; dated January 16, 2004
-DRS 5821-56; Main Chimney Radiation Monitor SPING Calibration; dated
January 22, 2004
-DIS 3900-01; Unit 2 Service Water Effluent Radiation Monitor Calibration; dated
June 4, 2003
-DIS 3900-01; Unit 3 Service Water Effluent Radiation Monitor Calibration; dated
April 16, 2004
-DRS 5830-01; Unit 3 Service Water Monitor Calibration; dated November 6, 2004
-DRS 5830-01; Unit 2/3 Liquid Radwaste Discharge Monitor Calibration; dated
March 26, 2004
-DIS 1300-04; Unit 2 Isolation Condenser Vent Radiation Monitor Calibration; dated
February 10, 2005
-DIS 1300-04; Unit 3 Isolation Condenser Vent Radiation Monitor Calibration; dated
February 11, 2005
-DIS 5700-03; Unit 2/3 Chimney Flow Monitor Calibration; dated July 21, 2003
-DIS 5700-02; Unit 2/3 Reactor Building Vent Stack Flow Calibration; dated
June 14, 2004
-Results of Analytics Radiochemistry Cross-Check Program for Dresden Nuclear
Power Station; Quarterly Results for 1st Quarter 2004 - 1st Quarter 2005
-Efficiency Calibrations and Lower Limit of Detection Determinations for Gamma
Spectroscopy Systems (6 detectors with multiple geometries); dated various periods
between January 2000 and April 2005
-Liquid Scintillation Counter (serial number 402097) Calibration and Lower Limit of
Detection Determination; dated January 25, 2005
-DTS 7500-13; Standby Gas Treatment System Visual Inspection (Train A and Train B);
dated May 26, 2004 and May 25, 2004, respectively
9 Attachment
-DTS 7500-07; Standby Gas Treatment System Charcoal Absorber Leak Test (Train A
and Train B); dated May 26, 2004 and May 25, 2004, respectively
-NCS Corporation Radioiodine Retention/Penetration/Efficiency Test Report; dated
June 9, 2004 (Train A - East and West Banks); dated May 28, 2004 (Train B - East
Bank)
-IR 00311151 and 00311622; Activity Detected in Unit 3 and Unit 2 Service Water
Effluent Samples; March 10 and 11, 2005
-IR 00315849; Increased Tritium in Well T-1; March 22, 2005
-IR 00317313; Service Water Sampling Requirements per ODCM; March 25, 2005
-IR 00326931; Unit 2/3 Chimney SPING Data Indication Flush Mode; April 20, 2005
-Audit NOSA-DRE-03-08; Radiological Environmental Monitoring Program, ODCM, Non-
Radiological Effluent Monitoring Audit Report; dated November 19, 2003
-Focus Area Self-Assessment Report; Radiological Effluent Control; dated
March 14, 2005
-Audit NOSA-DRE-04-04; Chemistry, Radwaste and Process Control Program; dated
May 25, 2004
-IR 00289411; Sludge Found During High Radiation Room Inspection;
January 10, 2005
-DTS 7500-11; DOP Testing of Unit 2/3 Standby Gas Treatment System HEPA Filters
(Train A and Train B); dated May 25 and May 26, 2004
-DOS 7500-02; Standby Gas Treatment System Surveillance and IST Test; dated
April 2, 2005
4OA1 Performance Indicator Verification
-Summary of Quarterly Dose Calculations from Liquid and Gaseous Effluents for 2004
through March 2005
4OA2 Identification and Resolution of Problems (71152)
-IR 239066; Negative Safety Trend Identified Within Security Department; April 26, 2005
-IR 324732; Operator Aid #159 Turnover Checklists; April 14, 2005
-IR 324902; NRC Identified Concerns; April 14, 2005
-IR 326630; U3 DW Hi Temp Alarm Setpoint Non-conservative vs. DEOP; April 20, 2005
-IR 327295; NOS Audit NOSA-DRE-05-01 (AR 287372) - Deficiency #1; May 11, 2005
-IR 327336; NRC Questions Actions Taken in SOC and MRC Closure of IRS;
April 21, 2005
-IR 329017; Generator H2 Pressure Dropped During Unit Shutdown; May 13, 2005
-IR 329045; Cracked Weld on U2 EDG Air Box Mount; May 24, 2005
-IR 329698; Large Quantity of Air Entrained in U3 Turbine Lube Oil; April 28, 2005
-IR 330004; D3M11 Forced Outage Due to 3b Rx. Recirc. PP.Seal Failure;
April 29, 2005
-IR 330030; Aggregate Reviews / Status of HCU PM 2005 Implementation;
April 29, 2005
-IR 330591; 3A MSDT Level Transmitter Calibration Drift; April 30, 2005
-IR 331420; Unplanned DOA 6500-12, Low Switchyard Voltage Entry; May 3, 2005
-IR 331430; Entered DOA 6500-11 for High Voltage on Bus 24-1; May 3, 2005
-IR 331875; M&TE Unable to Locate; May 4, 2005
-IR 331968; IEMA Representative Questions ECR for IR 326630; May 4, 2005
10 Attachment
-IR 332047; Unplanned Tech Spec Entry; May 5, 2005
-IR 332346; High Temperature (197 Deg F) on A Phase Bkr Supply Cable; May 5, 2005
-IR 332358; High Temperature (180 Deg F) on B Phase Bkr Supply Cable; May 5, 2005
-IR 332363; High Temperature (150 Deg F) on Hot Clg Twr MCC 2/3-7856-2B2;
May 5, 2005
-IR 333057; DGA-12 Hard Card Revised but Not the Procedure Section; May 9, 2005
-IR 333892; Inadequate Corrective Action Documentation in ATI 310957-02;
May 10, 2005
-IR 334295; Adverse Trend - Rising Water Level in Unit 3 Torus; May 11, 2005
-IR 334413; U3 125 Vdc Battery Cell 23 Sample Tube; May 12, 2005
-IR 335710; RB DP Low Condition for about 30 Seconds; May 16, 2005
-IR 335752; Experienced Difficulties Contacting BOC Gas; May 17, 2005
-IR 336040; NOS IDs Unidentified Cables/hoses; May 17, 2005
-IR 336506; Maintenance Rule Evaluations Not Completed as Required; May 18, 2005
-IR 337285; Fuel Pool Channel A Rad Hi Alarm; May 20, 2005
-IR 337403; Enter TS 3.3.6.2 Because of Failed Refuel FLR Rad Monitor; May 22, 2005
-IR 338273; NOS Ids Commitment Management Deficiency; May 25, 2005
-IR 338300; U2 SWRM Declared Inoperable; May 25, 2005
-IR 346783; Corrective Actions Not Effective ATI 270871; June 23, 2005
4OA3 Event Follow-up (71153)
-IR 325097; EC 6602 Lacks Documented Justification for no PMT; April 15, 2005
4OA5 Other Activities
TI 2515/163 Operation Readiness of Offsite Power
-IR 326685; Enter DOA 6500-12 and TS 3.8.1; May 11, 2005
-IR 333057; DGA-12 Hard Card Revised but Not the Procedure Section; May 9, 2005
-IR 333697; DOA 6500-12 Entered for Low Post Trip Red Bus Voltage; May 10, 2005
Operation of an Independent Spent Fuel Storage Installation (ISFSI) (60855.1)
-Certificate of Compliance (CoC) and the Technical Specifications; Revision 1
-Safety Evaluation Report; Revision 1
-Final Safety Analysis Report (FSAR); Revision 2
-Calculation Package On Hitran-140; Revision 2
-Prompt Investigation Report, No. 340904; Cask Transfer Facility (CTF) Lift Stopped
With Loaded Cask
-Engineering Evaluation, EC Eval 355831; Evaluation of Suspended Hi-Trac Storage
Unit in Cask Transfer Facility; Revision 0
-WO 817345-01; Troubleshooting and Repair of the CTF Instructions
-Maintenance Logs; dated April 7, 2005
-Condition Report; CTF Failure; dated June 6, 2005
-DAP 10-14A; Hi-Track Setdown at the CTF (ATI 340904-14) & Structural Qualification
of Hi-Track Recovery from DNPS CTF Drive Failure (AR340904);
72.48 Screening/Evaluation
-Special Procedure SP 05-05-006; Hi-Track Setdown at the CTF (ATI 340904-14);
Revision 0
11 Attachment
LIST OF ACRONYMS USED
ADAMS Agencywide Documents Access and Management System
ATI Action Tracking Item
ATWS Anticipated Transient Without Scram
CAP Corrective Action Program
CCSW Containment Cooling Service Water System
CoC Certificate of Compliance
CFR Code of Federal Regulations
CR Condition Report
CTF Cask Transfer Facility
DIS Dresden Instrument Surveillance
DOA Dresden Operating Abnormal Procedure
DOS Dresden Operating Surveillance
dP Differential Pressure
DRP Division of Reactor Projects
DRS Division of Reactor Safety
FIN Finding
FSAR Final Safety Analysis Report
GE General Electric
HEPA High Efficiency Particulate Air
HPCI High Pressure Core Injection System
IC Isolation Condenser
IGSCC Intergranular Stress Corrosion Cracking
IM Instrument Maintenance
IEMA Illinois Emergency Management Agency
IMC Inspection Manual Chapter
IR Issue Report
LER Licensee Event Report
MRC Management Review Committee
MWe megawatts electrical
NCV Non-Cited Violation
NRC Nuclear Regulatory Commission
ODCM Offsite Dose Calculation Manual
OSP Offsite Power
PARS Publicly Available Records
PI Performance Indicator
QHPI Quick Human Performance Investigation
RETS Radiological Effluent Technical Specifications
SBGT Standby Gas Treatment System
SDP Significance Determination Process
SOC Site Ownership Committee
SPING Station Particulate, Iodine and Noble Gas Monitor
SSC Structures, Systems, and Components
TI Temporary Instruction
TIP Traversing Incore Probe
12 Attachment
TS Technical Specification
TSO Transmission System Operator
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
WO Work Order 13 Attachment