ML043020589
| ML043020589 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 10/27/2004 |
| From: | Ring M Division Reactor Projects III |
| To: | Crane C Exelon Generation Co, Exelon Nuclear |
| References | |
| Download: ML043020589 (55) | |
See also: IR 05000237/2004010
Text
October 27, 2004
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 05000237/2004010;
Dear Mr. Crane:
On September 30, 2004, the 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 October 8, 2004.
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, five NRC identified findings and four self-revealed
findings of very low safety significance were identified. Seven of these findings were
determined to involve violations of NRC requirements. However, because of the very low safety
significance and because they were entered into your corrective action program, the NRC is
treating these seven findings as Non-Cited Violations, in accordance with Section VI.A.1 of the
NRCs Enforcement Policy. Additionally, a licensee-identified violation which was determined to
be of very low safety significance is listed in Section 4OA7 of this report.
If you contest any Non-Cited Violation in this report, you should provide a response with the
basis for your denial, within 30 days of the date of this inspection report, to the Nuclear
Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-001; with
copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United
States Nuclear Regulatory Commission, Washington, DC 20555-001; and the NRC Resident
Inspector at the Dresden facility.
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 05000237/2004010; 05000249/2004010
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 Department of Nuclear Safety
State Liaison Officer
Chairman, Illinois Commerce Commission
DOCUMENT NAME: G:\dres\ML043020589.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 N RIII E
NAME PPelke/dtp MRing
DATE 10/27/04 10/27/04
OFFICIAL RECORD COPY
C. Crane -3-
ADAMS Distribution:
AJM
MXB
RidsNrrDipmIipb
GEG
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: 05000237/2004010; 05000249/2004010
Licensee: Exelon Generation Company
Facility: Dresden Nuclear Power Station, Units 2 and 3
Location: 6500 North Dresden Road
Morris, IL 60450
Dates: July 1, 2004, through September 30, 2004
Inspectors: C. Phillips, Senior Resident Inspector
M. Sheikh, Resident Inspector
P. Pelke, Reactor Engineer
W. Slawinski, Senior Radiation Specialist
B. Palagi, Senior Operations Engineer
J. Neurauter, Reactor Engineer
B. Dickson, Senior Resident Inspector, Clinton
D. Eskins, Resident Inspector, LaSalle
R. Schulz, Illinois Emergency Management Agency
Approved by: M. Ring, Chief
Branch 1
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000237/2004010; IR 05000249/2004010, 07/01/2004 - 09/30/2004, Exelon Generation
Company, Dresden Nuclear Power Station, Units 2 and 3; Flood Protection, Outage Activities,
Radiological Environmental Monitoring and Radioactive Material Control Program, and Event
Followup.
This report covers a 3-month period of baseline resident inspection and announced baseline
inspection of radiation safety. The inspection was conducted by Region III inspectors and the
resident inspectors. The inspection identified nine Green findings, seven of which involved
Non-Cited Violations. 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: Initiating Events
Green. A self-revealed finding of very low safety significance was identified involving
several performance issues which resulted in the initiation of a Unit 2 manual scram on
April 24, 2004, due to failure of the 2A recirculation pump motor. The performance
issues included an inadequate process for rewinding the 2A recirculation pump motor
when it was installed in 1999, an inadequate evaluation of the testing of the motor
before installation, and the failure to perform post maintenance testing of the reactor
building closed cooling water system piping to identify leakage. This failure resulted in
the deposit of a conductive substance inside the motor. The licensee identified a
number of corrective actions including replacing the 2A recirculation pump motor and
revising Exelon Nuclear Engineering Standard NES-EIC-40.01 to include enhanced
testing requirements.
The finding was more than minor because it affected the initiating events cornerstone
objective to limit the likelihood of an initiating event. The finding was determined to be
of very low safety significance because all equipment and systems operated as
designed during the scram. (Section 4OA3)
Cornerstone: Mitigating Systems
Green. A finding of very low significance was identified by the inspectors on
June 5, 2004, involving a Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings. The abnormal operating procedure
instructions for response to external flooding, and surveillance test procedure for the
diesel driven pump necessary to provide make-up to the isolation condenser for
response to external flooding, were not adequate for the circumstances. The licensee
planned to change the surveillance test procedure and perform a full flow test of the
4 Enclosure
pump in the near future. The licensee planned to review the abnormal operating
procedure and revise the procedure as appropriate.
This finding was more than minor because it affected the equipment performance and
procedure quality attributes of the mitigating systems cornerstone, and affected the
cornerstone objective of ensuring the reliability and capability of systems that respond to
initiating events to prevent undesirable consequences. The issue was of very low safety
significance based on the low initiating event probability, and because of the slow onset
of the flooding and the reduced decay heat in the reactor core at the time recovery
actions would be necessary, the licensee would be able to reasonably perform recovery
actions that would prevent core damage. (Section 1R06)
Green. A finding of very low significance was identified on July 1, 2004, by the
inspectors involving a Non-Cited Violation of Technical Specification 3.3.1.1. The
licensee failed to take adequate corrective actions to prevent recurrence of inoperable
condenser low vacuum reactor protection system switches, failed to recognize the
switches were inoperable, and failed to enter the appropriate Technical Specification
Limiting Condition for Operation when the 3C and 2A turbine main condenser low
vacuum reactor protection system scram channels were inoperable. The primary cause
of the violation was related to the cross-cutting area of Problem Identification and
Resolution.
The finding was more than minor because it affected the mitigating systems cornerstone
objective by affecting the reliability of the reactor protection system. The finding was
determined to be of very low safety significance (Green) because one inoperable
channel would not prevent the reactor to scram on low condenser vacuum. Corrective
actions by the licensee included installing temporary vent valves on the 3C and 2A
sensing lines, enhancing operations training materials, revising the operationss
procedure, and performing internal and external condenser walkdowns during the next
outage on Unit 2 and Unit 3. (Section 4OA3)
Green. A finding of very low safety significance was identified by the inspectors
involving a Non-Cited Violation of Technical Specification 5.4.1. Operators failed to lock
manual feedwater isolation Valve 2-220-57B when returning the valve to service. This
valve was downstream of where the high pressure core injection (HPCI) system taps
into the feedwater line. The inspectors identified this issue during the drywell closeout
after the maintenance outage on September 23, 2004. The operators were counseled
and the licensee will require out-of-service checklists to be brought into the drywell in the
future. The primary cause of this violation was related to the cross-cutting issue of
Human Performance.
This issue was more than minor because it was repetitive. Other valves were found
unlocked inside the drywell by the inspectors during the drywell close out after the last
Unit 2 refueling outage in November 2003. The issue was of very low safety
significance because the valve was in the correct position. (Section 1R20)
Green. A self-revealed finding of very low safety significance involving a Non-Cited
Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, was identified. Inadequate procedural guidance resulted in the failure of
5 Enclosure
electricians to properly set the open torque switch bypass on Valve 2-1301-3, Isolation
Condenser Outboard Condensate Return Valve, on October 8, 1999. This resulted in
the failure of the valve to open during an event that occurred on April 24, 2004. The
licensee counseled the individuals and revised the maintenance procedure.
This finding was more than minor because it involved the equipment performance
attributes of the mitigating systems cornerstone and affected the cornerstone objective
of availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. This issue was of very low safety significance in
that the isolation condenser was only being used for pressure control at the time of the
event and other methods of pressure control were available, and in addition, the
licensee could have manually opened the valve if necessary. (Section 4OA3)
Cornerstone: Barrier Integrity
Green. A finding of very low safety significance was identified by the inspectors involving
a Non-Cited Violation of 10 CFR 50.65, Maintenance Rule, requirements. The
licensee failed to identify that the number of functional failures for the reactor building
ventilation system had exceeded the established performance criteria and did not move
the reactor building ventilation system into the a(1) category. Once identified, the
reactor building ventilation system was moved into the a(1) category on October 8,
2004. The licensee had not yet determined system goals or established corrective
actions by the close of the inspection period. The primary cause of the violation was
related to the cross-cutting area of Problem Identification and Resolution in that
functional failures of the system were not properly entered into the corrective action
program.
This issue was more than minor because it involved the design control and barrier
performance attributes of the barrier integrity cornerstone; and affected the cornerstone
objective of providing reasonable assurance that physical design barriers protect the
public from radionuclide releases caused by accidents or events. The issue was of very
low safety significance because the licensee was still able to maintain secondary
containment. (Section 1R12)
Green. A self-revealed finding of very low safety significance involving a Non-Cited
Violation of Technical Specification 3.7.4 was identified on April 28, 2004. The licensee
failed to correctly restore the control room emergency ventilation system to operable
status following maintenance. This left the control room emergency ventilation system
inoperable for greater than its Technical Specification allowed outage time. This finding
was self-revealed when the system did not operate properly several days later during a
routine system realignment. As corrective action, the licensee revised a procedure to
give better guidance on how to remove the temporary modification.
The issue was more than minor because it affected the Barrier Integrity Cornerstone
attributes of design and configuration control and the cornerstone objective of protecting
persons in the control room from radionuclide releases caused by accidents or events.
The issue was of very low safety significance due to the short duration of the condition
of the system. (Section 4OA3)
6 Enclosure
Green. A finding of very low safety significance was identified on August 3, 2004, by the
inspectors during the walkdown of a corrective action for a previous event. The licensee
had an abnormal operating procedure requirement to have tools and equipment staged
to install a temporary modification to keep the control room emergency ventilation
system dampers open in the event of an accident. The equipment necessary to install
the temporary modification was in various stages of disarray. Some equipment was not
labeled and some necessary tools were missing. The licensee identified a number of
corrective actions including properly packaging the necessary tools and equipment,
revising procedures, and initiating a training request to ensure operations personnel are
properly trained in the use of the tools and equipment.
The finding was more than minor because it affected the Barrier Integrity Cornerstone
attributes of configuration control and the cornerstone objective of protecting persons in
the control room from radionuclide releases caused by accidents or events. The issue
was of very low safety significance due to it only impacting the radiological barrier
function of the control room emergency ventilation system. This was not a violation of
regulatory requirements. (Section 40A3)
Cornerstone: Public Radiation Safety
Green. A self-revealed finding of very low safety significance involving a Non-Cited
Violation of 10 CFR 20.1501 was identified on October 16, 2003, following a gatehouse
radiation monitor alarm at the Braidwood Nuclear Station upon detecting a discrete
radioactive particle (DRP) on a workers boot. The DRP was attributed to the workers
activities at the Dresden facility approximately 1 year earlier. The DRP was not
identified at the Dresden Station due to an inadequate radiation survey of the worker
following a personnel contamination monitor alarm and also because of limitations with
the radiation monitoring instrumentation used at the licensees egress to the
radiologically controlled area (RCA).
Corrective actions for this finding included tailgate training to radiation protection
staff that respond to contamination monitor alarms, improvements to automated
radiation monitoring capabilities at the main RCA egress, and actions to enhance
gamma-sensitivity of those automated radiation monitors located in alternate egress
areas and at the protected area gatehouse.
The finding was more than minor because it was associated with the Program and
Process and Human Performance attributes of the Public Radiation Safety
Cornerstone, and affected the cornerstone objective that ensures adequate protection of
public health and safety from exposure to radioactive materials that are released into the
public domain. The issue represents a finding of very low safety significance because
public radiation exposure resulting from the problem was not greater than 0.005 rem
total effective dose equivalent, the licensee did not have greater than five radioactive
material control occurrences in the previous eight quarters and the dose to the involved
worker was approximately one percent of the regulatory (10 CFR 20.1201) occupational
dose limits for adults. An associated Non-Cited Violation of 10 CFR 20.1501 was
identified for the failure to conduct an adequate survey to ensure proper control of
7 Enclosure
radioactive material as required by 10 CFR Part 20, Subpart I, Storage and Control of
Licensed Material (Section 2PS3).
B. Licensee-Identified Violation
A violation of very low safety significance which was identified by the licensee has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensees corrective action program. This violation and corrective
actions are listed in Section 4OA7 of this report.
8 Enclosure
Report Details
Summary of Plant Status
Unit 2 began the inspection period at 912 MWe (100 percent of rated electrical capacity).
- On August 13, 2004, a controlled shutdown began for a forced outage for the purpose
of repairing a crack on the generator footing. The unit was returned online
August 21, 2004. The unit did not achieve full power because of vibration on the
- 9 turbine bearing.
- On September 18, 2004, a controlled shutdown began for a forced outage for the
purpose of repairing the main turbine generator. The unit was returned online
September 25, 2004.
Unit 3 began the inspection period at 912 MWe (100 percent of rated electrical capacity).
- On several occasions throughout the inspection period, load was reduced to perform
control rod adjustments, with the unit returning to full load during the same day.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R04 Equipment Alignment (71111.04Q&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.
The inspectors performed partial equipment alignment walkdowns of the:
- 3A Core Spray System;
- Unit 2, Division II, Low Pressure Coolant Injection System;
- Unit 2/3, A Train, Standby Gas Treatment System; and
- Unit 3 High Pressure Coolant Injection System.
9 Enclosure
b. Findings
No findings of significance were identified.
.2 Complete System Walkdown
a. Inspection Scope
The inspectors performed one complete semiannual walkdown of the Unit 3 control rod
drive system. The inspectors reviewed the electrical and mechanical system checklist
and drawings to ensure all vital components in this system were energized. 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 all temporary modifications and
operator workarounds to verify the operational impact on the system. The inspectors
reviewed licensee condition reports (CRs) and issue reports (IRs), to verify past issues
that had been identified and their corrective actions.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05)
.1 Routine Inspection (Quarterly)
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 589' isolation condenser area,
(Fire Zone 1.1.2.5.A);
- Unit 3 reactor building, elevation 589' isolation condenser area,
(Fire Zone 1.1.1.5.A);
- Unit 2 turbine building, elevation 469'-6" condensate pumps (Fire Zone 8.2.1.A);
- Unit 2 turbine building, elevation 495' containment cooling service water pumps
(Fire Zone 8.2.2.A);
- Unit 2 turbine building, elevation 517' diesel generator (Fire Zone 9.0A);
- Unit 3 turbine building, elevation 495' containment cooling service water pumps
(Fire Zone 8.2.2.B);
- Unit 3 turbine building, elevation 469'-6" condensate pumps (Fire Zone 8.2.1.B);
- Unit 2 reactor building, isocondenser pipe chase (3 valve room), elevation
545'-6" (Fire Zone 1.1.2.5.c); and
- Unit 3 reactor building, elevation 545'-6" (Fire Zone 1.1.1.3).
10 Enclosure
b. Findings
No findings of significance were identified.
.2 Weekly Fire Marshal Walkdown
a. Inspection Scope
The inspectors accompanied the Unit 3 field supervisor during a weekly fire marshal
walkdown of the Unit 2 and Unit 3 reactor and turbine buildings. The inspectors
observed that the field supervisor checked hot work activities in progress, general fire
protection housekeeping, fire protection equipment was not blocked and appeared to be
in good working order, fire doors and dampers were in good condition, and emergency
lights appeared to be in good working order.
b. Findings
No findings of significance were identified.
1R06 Flood Protection (71111.06)
a. Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report flood analysis
documents and reviewed the licensees procedures for external flooding. The
inspectors reviewed the licensees procedures for external flooding for ensuring proper
safe shutdown of the plant, and reviewed the licensees previously implemented
corrective actions for deficiencies associated with flood protection.
b. Findings
Introduction: The inspectors identified a Non-Cited Violation of 10 CFR 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, having very low safety
significance (Green) for the failure to develop adequate surveillance test and operating
procedures for equipment that was the sole source of makeup water to the isolation
condensers for both units during a design basis flood.
Description: Dresden Updated Final Safety Analysis Report (UFSAR) Section 2.4.3
stated that the NRC concluded in Systematic Evaluation Program (SEP) Topic II-3.B
that a flow of 490,000 cubic feet per second in the Illinois River would result in a still
water flood elevation of 525 feet. Adding wave runup to the stillwater flood elevation
yields a site probable maximum flood (PMF) elevation of 528 feet. This is about 11 feet
above grade. Water at this height puts all emergency core cooling system equipment
under water. Therefore, the sole sources of decay heat removal for both units would be
the isolation condensers. After initiation, make up water eventually needs to be added
to the shell side of the isolation condenser.
The UFSAR Section 3.4.1.1, External Flood Protection Measures, stated that if
forecasted flood levels exceed 517 feet, 150 gallon per minute emergency makeup
11 Enclosure
pumps are connected to the fire system. The UFSAR did not say why the pumps were
to be connected. Procedure DOA 0010-04, Floods, Revision 16, stated that a portable
diesel driven pump will be brought into the reactor building, hoisted into the air, and
connected to the fire main system to supply makeup water to the isolation condensers.
The inspectors reviewed the 10 CFR 50.59 screening performed for the procedure
change that went from four gasoline powered pumps to one diesel driven pump. The
10 CFR 50.59 screening did not address the change in the number and type of pumps.
This is an unresolved item pending NRC review of the licensees planned corrective
action to perform a 10 CFR 50.59 evaluation and subsequent revision to UFSAR
Section 3.4.1.1. (URI 05000237/2004010-01; 05000249/2004010-01)
Calculation DRE99-0035, Capacity and Discharge Head For Portable Isolation
Condenser Make-up Pump To Be Used During Flood Conditions, Revision 2,
conservatively assumes that the portable make-up pump to the isolation condensers
would be required to remove the decay heat 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after reactor shutdown is reached.
The calculation concludes that, in order to supply sufficient makeup flow, the portable
pump must be able to supply 174 gallons per minute per reactor at a discharge head of
263 feet. The vendor manual DRE VTIP MANL GC43-001, Godwin Pumps HL80 M
Dri-Prime Pump Operating and Maintenance Manual, Revision 3, shows in Figure 6
that the pump can produce this amount of flow at the required head, but only at a speed
of 2400 rpm.
The NRC identified on June 5, 2002, that this pump was not routinely tested; and
therefore, its capability to perform its function during a flood was suspect. This was
identified in CR 111005. Assignment 5 from CR 111005 was to evaluate the
preventative maintenance and surveillances that should be performed relating to the
emergency diesel pump and other activities associated with DOA 0010-04. This was
completed on September 10, 2002. The licensee developed and implemented
DOS 1300-04, Operation Of The Isolation Condenser External Flood Emergency
Make-up Pump, on April 24, 2003. Per the surveillance test, DOS 1300-04, Revision 2,
Step I.2.g, the pump is run at a speed of 1800 rpm. Therefore the surveillance test does
not evaluate the ability of the pump to run at the speed (2400 rpm) necessary for the
pump to perform its function.
Page 9 of Calculation DRE99-0035 states that the timetable for the licensing basis flood
is given in Technical Evaluation Report (TER) C5257-421, Hydrological
Considerations, dated May 7, 1982. The report concludes that the flood waters will rise
from 509 feet to 517 feet in 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> assuming dam gates open to 16 feet. The
Technical Requirements Manual and Procedure DOA 0010-04 both require that both
units shutdown when the river elevation reaches 509 feet. Therefore, the amount of
water needed for the isolations condensers is based on decay heat 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after
shutdown.
As mentioned above, the required amount of flow to the isolation condenser to remove
decay heat 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after shutdown would require a diesel driven pump speed of
2400 gpm. Procedure DOA 0010-04 has no mention as to what speed the diesel driven
pump should or can be run. Procedure DOA 0010-04, Step D.14.f stated, adjust the
throttle to increase flow. The inspectors conducted an interview with members of the
12 Enclosure
non-licensed operator training staff that conducted training on the diesel driven pump to
be used during a flood. The inspectors asked if given the flood scenario, at what speed
would you operate the pump? One trainer stated that given the surveillance (DOS
1300-04) has the operator test the pump at 1800 rpm he would run the pump at that
speed. The inspectors asked if no water was flowing at that speed what would you do?
Both trainers responded that the pump would be secured and a valve lineup would be
performed.
Procedure DOA 0040-02, Localized Flooding In Plant, Revision 15, Step A.1.a, stated
that for the isolation condenser external flood emergency make-up pump, The
maximum vertical suction lift from water source to pump impeller cannot be in excess of
27 feet. The inspectors requested that system engineering personnel check the length
of the suction hose. The system engineer informed the inspectors that the suction hose
was 30 feet long. Procedure DOA 0010-04, Step D.9.i, states, Using the Rx Building
Crane, raise the emergency make-up pump to between 12 and 15 feet above the floor;
and Step D.17, states, WHEN water recedes to below EL 518 ft, THEN relocate suction
hose from diesel-driven emergency make-up pump to draw water from the nearest
ECCS [emergency core cooling system] corner room. The inspectors verified that the
distance between the location of the pump impeller when the pump is hoisted into the air
and the ECCS corner room was greater than 30 feet. This means there would be no
suction source for the pump once the water started to recede.
Technical Evaluation Report (TER) C5257-421 was prepared for the NRC by the
Franklin Research Center to evaluate the effects of flooding on Dresden Unit 2. This
TER points out that normal reactor cooling procedures will not ensue immediately
following the time flood waters drop below elevation 509, consequently the operation of
the gasoline-driven pumps will be required for a significant period of time, i.e., more than
3 days. The licensee did not estimate how long the diesel driven pump may be
needed; and therefore, did not estimate how much fuel for the diesel driven pump
needed to be pumped into barrels and staged in the reactor building in advance. The
licensee does not know how long the flooding might impact the site and how much fuel
might be needed to be staged in advance.
Analysis: The inspectors determined that the failure to implement adequate surveillance
test and abnormal operating procedures that provided instructions to ensure an
adequate supply of make-up water to the isolation condenser during flood conditions to
prevent core damage was a performance deficiency warranting a significance evaluation
in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue
Screening, issued on June 20, 2003. The inspectors determined that the finding was
more than minor because it (1) involved the equipment performance and procedure
quality attributes of the mitigating systems cornerstone and (2) affected the cornerstone
objective of ensuring the reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. The inspectors also determined that the
failure to implement an adequate surveillance test procedure after it was identified that
there was no test procedure in 2002, also affected the cross-cutting area of Problem
Identification and Resolution.
The inspectors determined that the finding could be evaluated using the SDP in
accordance with IMC 0609, Significance Determination Process, Appendix A, dated
13 Enclosure
September 10, 2004, because the finding was associated with the reliability of a
mitigating system. The inspectors concluded that the diesel driven make-up pump
would be a mitigating system in the case of the PMF. For the Phase 1 screening, the
inspectors answered No to the first four questions under the mitigating systems
column. The inspectors then went to the Phase 1 worksheet for Seismic, Fire, Flooding,
and Severe Weather Criteria. Question 1 was answered Yes. Question 2.c was
answered Yes. Returning to Question 5 under the mitigating systems on the Phase 1
screening sheet this question was answered Yes and referred to the Regional Office
for a Phase 3 analysis. The Phase 3 analysis performed by the Senior Reactor Analyst
(SRA) concluded that the safety significance of this finding based on the change in core
damage frequency to be Green. The Phase 3 analysis reviewed the potential failure
probabilities based on the procedure and equipment inadequacies. The SRA, in
discussions with the licensee and the resident inspectors, determined that based on the
low initiating event probability, and because of the slow onset of the flooding and the
reduced decay heat in the reactor core at the time recovery actions would be necessary,
the licensee would be able to reasonably perform recovery actions that would prevent
core damage. A Green finding represents a finding of very low safety significance.
Enforcement: The inspectors identified that the licensee did not have procedures
appropriate to the circumstances of external plant flooding on June 5, 2004. The failure
to have procedures appropriate for the circumstances of a PMF was a violation of
10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, which
states in part, Activities affecting quality shall be prescribed by documented
instructions, procedures, or drawings, of a type appropriate to the circumstances...
Contrary to the above, on June 5, 2004, (1) surveillance procedure DOS 1300-04,
Revision 2, for the portable diesel driven isolation condenser make-up pump did not test
the diesel at the speed (2400 rpm) necessary to deliver the minimum amount of flow to
make up to the isolation condensers in the event of a flood; (2) abnormal operating
procedure DOA 0010-04, Revision 16, did not specify the minimum required speed of
the diesel driven make-up pump for the operators; (3) the suction hose from the pump
was too short to successfully accomplish the step in procedure DOA 0040-02,
Revision 15, that directed the operators to move the suction hose to the nearest corner
room when the flood waters started to recede; and (4) none of the procedures specified
how much fuel oil was necessary to be staged on the 545 foot level of the reactor
building prior to the onset of flooding. The licensee planned to change the surveillance
test procedure DOS 1300-04 to run the pump at 2400 rpm and perform a full flow test of
the pump in the near future. The licensee planned to review DOA 0010-04 and revise
the procedure as appropriate. Because this issue is of very low safety significance and
has been entered into the licensees corrective action program (Issue Reports, 246038
and 261167), this violation is being treated as a Non-Cited Violation, consistent with
Section VI.A., of the NRC Enforcement Policy. (NCV 05000237/2004010-02;
14 Enclosure
1R11 Licensed Operator Requalification (71111.11Q)
a. Inspection Scope
The inspectors observed an evaluation of an operating crew on September 27, 2004.
The scenario consisted of a recirculation flow controller failure, a reactor building closed
cooling water pump trip, an instrument line break in the drywell which required flooding
of the reactor pressure vessel, and a failure of a core spray pump. The inspectors
verified that the operators were able to complete the tasks in accordance with applicable
plant procedures and that the success criteria as established in the job performance
measures were satisfied. 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 condition reports written
regarding licensed operator requalification training were entered into the licensees
corrective action program with the appropriate significance characterization.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
a. Inspection Scope
The inspectors reviewed the licensees overall maintenance effectiveness for
risk-significant mitigating systems. The inspectors also reviewed whether the licensee
properly implemented the Maintenance Rule, 10 CFR 50.65, for the systems.
Specifically, the inspectors determined whether:
- the systems were scoped in accordance with 10 CFR 50.65;
- performance problems constituted maintenance rule functional failures;
- the systems have been assigned the proper safety significance classification;
- the systems were properly classified as (a)(1) or (a)(2); and
- the goals and corrective actions for the systems were appropriate.
The above aspects were evaluated using the maintenance rule program. The
inspectors also verified that the licensee was appropriately tracking reliability and/or
unavailability for the systems.
The inspectors reviewed the following systems:
- Unit 3 Control Rod Drive System;
- Reactor Building Containment Cooling Service Water; and
b. Findings
Introduction: The inspectors identified a Non-Cited Violation (NCV) of 10 CFR 50.65
having very low safety significance (Green) for failing to adequately implement the
15 Enclosure
maintenance rule. The licensee failed to move the reactor building ventilation system to
category (a)(1) monitoring of 10 CFR 50.65 after exceeding the performance criteria
established for reliability of four functional failures in 2 years.
Description: The licensee was not able to maintain a .25-inch vacuum in the secondary
containment relative to atmosphere on June 19, 2002, June 24, 2002, July 31, 2002,
October 24, 2003, March 7, 2004, April 24, 2004, and July 22, 2004. On each date the
differential pressure was positive for less than the Technical Specification (TS) 3.6.4.1.1
Limiting Condition For Operation time. The licensees maintenance rule program
considered a positive pressure in the secondary containment as a functional failure of
the reactor building ventilation system. These events were not properly addressed by
the licensees corrective action program. The July 31, 2002 event was documented in
the operators logs but no condition report was written. The April 24, 2004 event was
entered into the corrective action program as CR 216750, and was coded as a
maintenance rule functional failure but was not counted as a maintenance rule
functional failure.
The licensee had not established a repair or replacement program for the reactor
building ventilation exhaust fan back-draft damper actuator springs. The springs
provided the motive force for the back-draft dampers. The damper vendor
recommended replacement of the springs within 10 years. The actuator springs were
18 years old. As a result of spring relaxation, the Unit 2A and 2C exhaust fan back-draft
dampers would only open about 5 percent, resulting in a failure to maintain the .25 inch
vacuum.
The licensees performance criteria for the reactor building ventilation system,
established in the maintenance rule database program, stipulated that more than four
functional failures in 2 years required transfer of the reactor building ventilation system
to 10 CFR 50.65 Section (a)(1) monitoring from Section (a)(2). The licensee had five
functional failures between July 31, 2002, and July 22, 2004, and six functional failures
between June 19, 2002, and April 24, 2004. The licensee did not move the reactor
building ventilation system to (a)(1).
Analysis: The inspectors determined that the failure to correctly enter the events into
the corrective action program which resulted in the failure to move the reactor building
ventilation system from 10 CFR 50.65 Section (a)(2) to (a)(1) was a performance
deficiency warranting a significance evaluation in accordance with IMC 0612, Power
Reactor Inspection Reports, Appendix B, Issue Screening, issued on June 20, 2003.
The inspectors determined that the finding was more than minor because it:
(1) involved the design control and barrier performance attributes of the barrier integrity
cornerstone; and (2) affected the cornerstone objective of providing reasonable
assurance that physical design barriers protect the public from radionuclide releases
caused by accidents or events. The inspectors determined that the finding also affected
the cross-cutting area of Problem Identification and Resolution.
The inspectors determined that the finding could be evaluated using the SDP in
accordance with IMC 0609, Significance Determination Process, Appendix A,
Determining the Significance of Reactor Inspection Findings for At-Power Situation,
dated September 10, 2004, because the finding was associated with a degraded reactor
16 Enclosure
building containment barrier. For the Phase 1 screening, the inspectors answered Yes
to Question 1 under the Containment Barriers Cornerstone column because the finding
only represents a degradation of the radiological barrier function of the reactor building.
The finding screened as Green.
Enforcement: Section (a)(2) of 10 CFR 50.65 stated, in part, that monitoring as
specified in paragraph (a)(1) is not required where it has been demonstrated that the
performance of a structure, system, or component is being effectively controlled through
the performance of appropriate preventive maintenance, such that the structure,
system, or component remains capable of performing its intended function. The
licensees performance criteria for the reactor building ventilation system, established in
the maintenance rule database program, stipulated that more than four functional
failures in 2 years required transfer of the reactor building ventilation system to 10 CFR
50.65 Section (a)(1) monitoring from Section (a)(2). The licensee had five functional
failures between July 31, 2002 and July 22, 2004 and six functional failures between
June 19, 2002 and April 24, 2004. The functional failures were due to inappropriate
preventative maintenance. The licensee did not move the reactor building ventilation
system to (a)(1) until the inspectors identified this issue. The licensee convened a
maintenance rule evaluation panel on October 8, 2004, and moved the reactor building
ventilation system to (a)(1). System goals have not yet been established. Because this
violation was of very low safety significance and because it was entered into the
corrective action program (Issue Report 256499), this violation is being treated as a
Non-Cited Violation, consistent with Section VI.A of the NRC Enforcement Policy.
(NCV 05000237/2004010-03; 05000249/2004010-03)
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 3, 250 VDC battery jumpering of cell 113;
- Unit 2 high pressure coolant injection room cooler fan emergent work;
- Planned maintenance of 3B core spray;
Valves 2-1501-3A/2-1501-18A/2-150138A;
- Unit 2/3, B train, standby gas treatment planned maintenance; and
- Planned maintenance of 3A core spray.
b. Findings
No findings of significance were identified.
17 Enclosure
1R15 Operability Evaluations (71111.15)
.1 Routine Operability Evaluation (OE) Reviews
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:
- Units 2 & 3 High Pressure Coolant Injection (HPCI) May Not be Available for
Some Safe Shutdown Events Assumed in the Licensing Basis Due to Water
Intrusion into the HPCI Steam Line (OE 04-002);
- Unit 3 Containment Cooling Service Water Back-Up Keep Fill Line is not
Supported per Code Allowance (OE 04-006);
- Units 2 & 3 CR105X Dried Grease Could Degrade Operation of Contactor
(OE 04-004);
- IR 00245395, "NRC Concern With Reactor Level Density Error;"
- Low Unit 2 Switchyard Voltage on August 23, and September 14, 2004;
- 2(3)-0203-3A Target Rock Safety Relief Valve (OE04-014);
- CRD operability (IR 0257827);
- Secondary Containment, IRs 0238241, 0249994, and 0246489;
- Main Condenser Hood/Bay (OE 04-008, Revision 0); and
- Unit 2 & 3 2A and 3C Condenser Bay Vacuum Indication/Switch Sometimes
Indicates a Non-conservative Value after a Flow Reversal to East-to-West Flow
(OE 04-008, Revision 1).
b. Findings
No findings of significance were identified.
1R17 Permanent Plant Modification (7111.17A)
a. Inspection Scope
The inspectors reviewed one permanent plant modification to verify the design
adequacy to ensure licensing and design bases were maintained, and to ensure
functionality of interfacing structures, systems, and components. The modification
reviewed included the following:
- Replacement of Standby Gas Treatment Solenoid Valve 2/3-7541-43B on
AO-7510-B.
b. Findings
No findings of significance were identified.
1R19 Post Maintenance Testing (71111.19)
18 Enclosure
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:
- Disassemble and Inspect 2B Core Spray Minimum Flow Stop Check Valve;
- Unit 3, 250 VDC Battery Jumpering of Cell 113;
- Testing of the 3B Core Spray Following 2Y EQ GE Pump Motor Maintenance;
- Unit 2/3, B train, Standby Gas Treatment, Testing of Valve Operator 2/3-7507-
B Following Preventive Maintenance on Limitorque; and
- Inspect/Repair Unit 2 HPCI Discharge Testable Check Valve 2-2301-7.
b. Findings
No findings of significance were identified.
1R20 Refueling and Outage Activities (71111.20)
.1 Unit 2 Forced Maintenance Outage August 2004
a. Inspection Scope
On August 14, 2004, the licensee commenced a 6-day forced maintenance outage.
The licensee identified a crack on a weld on one of the main turbine generator support
footings. General Electric, while performing a review of Unit 2 main turbine vibrations,
informed the station of a concern that the crack could propagate into the generator
housing. Since the generator is cooled by hydrogen the result could have possibly led
to an escape of hydrogen leading to the potential for a fire and/or explosion. General
Electric recommended the shutdown of Unit 2 until the crack could be repaired.
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 turnover meetings to verify that the current
shutdown risk status was well understood and communicated;
- 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 its 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;
19 Enclosure
- monitored licensees troubleshooting efforts for emergent plant equipment
issues;
- performed plant walkdowns to observe ongoing work activities;
- conducted in-office reviews of selected issues that the licensee entered into its
corrective action program to verify that identified problems were being entered
into the program with the appropriate characterization and significance;
- observed control rod withdrawals and initial transition to criticality; and
- monitored mode switch changes and observed portions of power ascension.
b. Findings
No findings of significance were identified.
.2 Unit 2 Maintenance Outage September 2004
During the Unit 2 outage in August 2004, the licensee attempted to reduce vibrations on
the number 9 turbine bearing by realigning the main generator. That effort was
unsuccessful. Unit 2 generator vibrations were still high at a lower power level than
those seen previous to the August outage. Unit 2 was shutdown again on
September 18, 2004, for a scheduled 26 day outage in order to send the generator
offsite to be rewound. Testing during the shutdown convinced licensee management
that the actual problem causing the high vibration was soft foot conditions (foundation
not as firm as it should be) under three of the eight generator support structures. The
licensee repaired the soft conditions and added balancing weights to the main generator
rotor. The unit was restarted and returned to full power on September 26, 2004.
The inspectors performed the following activities daily:
- attended control room operator turnover meetings to verify that the current
shutdown risk status was well understood and communicated;
- performed walkdowns of the main control room to observe the alignment of
systems important to safe/shutdown risk condition;
- monitored licensees troubleshooting efforts for emergent plant equipment
issues, specifically the failure of 2-2301-7, high pressure coolant injection (HPCI)
testable discharge check valve to pass its cold shutdown surveillance;
- performed a drywell closeout walkdown;
- observed control rod withdrawals and initial transition to criticality; and
- monitored mode switch changes and observed portions of power ascension.
b. Finding
Introduction: The inspectors identified a Non-Cited Violation (NCV) of TS 5.4.1 having
very low safety significance (Green) for failing to lock open Valve 2-0220-57B,
Feedwater Manual Isolation Valve.
Description: The inspectors identified during a drywell closeout of Unit 2, on
September 23, 2004, that Valve 2-0220-57B was not locked open as required by
out-of-service checklist 31383 performed on September 22, 2004. The licensee had
taken 2-0220-57B out-of-service closed during the outage to perform corrective
20 Enclosure
maintenance on the 2-2301-7, high pressure coolant injection (HPCI) discharge check
valve. The inspectors verified that 2-220-57B was open, but the locking device was
wrapped around the valve yoke and not the valve handwheel. Valve 2-220-57B was in
the flow path for HPCI injection and B train of feedwater.
Analysis: The inspectors determined that failing to lock the valve open was an operator
performance deficiency warranting a significance evaluation in accordance with
IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition
Screening, issued on June 20, 2003. The inspectors determined that the finding was
more than minor because it affected the configuration control and human performance
attributes of the Mitigating Systems cornerstone; and affected the cornerstone objective
of ensuring the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. In addition, this was not the first time the
NRC identified drywell valves that were in the correct position but not locked per
licensee procedure. During the Unit 2 refueling outage drywell close out on
November 9, 2003, the inspectors identified that the two reactor head vent valves
2-0299-59 and 2-0299-60 were closed but not locked closed per licensee procedure.
This was documented in Condition Report 185823. Regarding Valve 2-220-57B,
licensee management personnel stated that, when interviewed, the operators stated that
the valve was difficult to open and when they finished they forgot to lock the valve. The
individuals did not have a copy of the clearance order checklist with them in the drywell
in an effort to reduce dry active waste. However the operators were briefed prior to the
task and the clearance checklist clearly stated the valve was to be locked. Therefore,
this finding also affected the cross-cutting area of Human Performance.
The inspectors completed a significance determination of this issue using IMC 0609,
Significance Determination Process (SDP), Appendix A, Determining the Significance
of Reactor Inspection Findings for At-Power Situations, dated September 10, 2004. For
Phase I screening the inspectors answered No to Question 1 under Mitigating Systems
Cornerstone because the finding did not result in a loss of function for either the
feedwater or HPCI systems. The finding screened as Green.
Enforcement: Technical Specification 5.4.1 required, in part, that written procedures
shall be established, implemented, and maintained covering the applicable procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, Paragraph 1.c
recommends procedures for equipment control (e.g., locking and tagging). One of the
equipment control procedures that implemented this TS was OP-MW-109-101,
Clearance and Tagging, Revision 2. Step 10.4.1.5.A, stated, PLACE equipment in
the positions/conditions specified on the clearance checklist. Clearance Checklist
31383 Step 18, required valve 2-220-57B to be locked in the open position. The
operators opened but did not lock the valve in the required position. The valve was in
the open but unlocked position for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The non-licensed operators were
temporarily removed from shift duties and a fact finding review was scheduled for
completion after the end of the inspection period. The individuals were counseled. The
licensee planned to require carrying clearance checklists into the drywell in the future.
Because this violation was of very low safety significance and it was entered into the
licensees corrective action program (Issue Report 256029), this violation is being
21 Enclosure
treated as a Non-Cited Violation, consistent with Section VI.A of the NRC Enforcement
Policy. (NCV 05000237/2004010-04)
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 TSs.
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:
- DIS 0500-06, Rev. 20, Condenser Low Vacuum Pressure Switches Channel
Calibration and Channel Functional Test;
- DOS 0700-05, Rev. 09, Intermediate Range Monitor Upscale and Inoperative
Functional Testing;
- Emergency Relief Valve Pressure Switches; and
- Unit 2/3, B Train, Standby Gas Treatment, Preventative Maintenance
Surveillance on Limitorque Valve Operator 2/3-7504-B.
1R23 Temporary Modification (71111.23)
a. Inspection Scope
The inspectors screened three active temporary modifications and assessed the effect
of the temporary modifications on safety-related systems. The inspectors also
determined if the installation was consistent with system design:
- Temporary Configuration Change Package No. 347984, Revision 1, Install
Temporary Recorder to Monitor Unit 2 Steam Dryer Parameters;
- Control room ventilation system as called for in DOA 5750-01; and
- Temporary Configuration Change Package No. 349028, Revision 0, Install
Bleeder Valve on the Unit 3 C Condenser Hood Low Vacuum Sensing Line to
Prevent Moisture Buildup.
b. Findings
No findings of significance were identified.
22 Enclosure
1EP6 Drill and Training Evaluations (71114.06)
September 27, 2004, Emergency Preparedness Performance Indicator Drill
a. Inspection Scope
The inspectors observed station personnel during a licensee only participation
emergency preparedness drill exercise on September 27, 2004, to determine the
effectiveness of drill participants and the adequacy of the licensees critique in
identifying weaknesses and failures. The drill scenario involved failure of the master
recirculation flow controller, trip of the 2A reactor building closed cooling water pump, a
break in an instrument line in the drywell, and failure of the core spray pump.
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Public Radiation Safety
2PS3 Radiological Environmental Monitoring Program (REMP) And Radioactive Material
Control Program (71122.03)
.1 Inspection Planning - Reviews of Radiological Environmental Monitoring Reports and
Data
a. Inspection Scope
The inspectors reviewed the 2002 and 2003 Annual Radiological Environmental
Operating Reports, the results of monthly radiological environmental monitoring
analyses for January through May 2004, and the most recent licensee assessment
results to verify that the REMP was implemented as required by TSs and the Offsite
Dose Calculation Manual (ODCM). The inspectors reviewed the radiological
environmental reports for changes to the ODCM with respect to environmental
monitoring, commitments in terms of sampling locations, monitoring and measurement
frequencies, land use census, the sample analysis vendors inter-laboratory comparison
program, and analysis of radiological environmental sample data. The inspectors
reviewed the ODCM to identify the environmental monitoring stations and evaluated the
locations of these stations and the types of samples collected from each to determine if
they were consistent with the ODCM and NRC guidance in Regulatory Guide 1.21,
Measuring, Evaluating, and Reporting Radioactivity in Solid Wastes and Releases of
Radioactive Materials in Liquid and Gaseous Effluents from Light Water Cooled Nuclear
Power Plants, and in Regulatory Guide 4.8, Environmental TSs for Nuclear Power
Plants. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) for
information regarding the monitoring program and the Emergency Response Plan for
information regarding meteorological monitoring instrumentation to determine whether
the environmental monitoring program was developed consistent with its design basis.
23 Enclosure
The inspectors reviewed the scope of the licensees audit program to verify that it met
the requirements of 10 CFR 20.1101(c).
These reviews represented one inspection sample.
b. Findings
No findings of significance were identified.
.2 Onsite Inspection Activities
a. Inspection Scope
The inspectors walked-down all eight indicator environmental air sampling stations, the
sole control station, both operable special air sampling stations, and approximately
25 percent of the thermoluminescence dosimeter (TLD) monitoring stations. The
walkdowns were performed to determine whether these environmental stations were
located as described in the ODCM, to assess equipment material condition and
operability, and to verify that environmental station orientation relative to plant effluent
release points, vegetation growth control, and equipment configuration allowed for the
collection of representative samples.
The inspectors accompanied the REMP contract technician and observed the collection
and change-out of air particulate and charcoal cartridges at each air sampling station
and observed the collection of surface water samples to determine whether appropriate
practices were used to ensure sample integrity and to verify that sampling techniques
were in accordance with the licensees procedures.
The meteorological tower was walked down by the inspectors to verify it was adequately
sited and that instrumentation was installed consistent with Regulatory Guide 1.23,
Meteorological Programs in Support of Nuclear Power Plants. The inspectors verified
that the meteorological instruments were operable, calibrated, and maintained in
accordance with the Emergency Response Plan, the guidance provided in NRC Safety
Guide 23, and applicable licensee procedures. The inspectors compared real-time data
collected at the meteorological tower versus the time-averaged data transmitted to the
control room to verify data integrity.
The inspectors reviewed each event documented in the Annual Environmental
Monitoring Reports which involved a missed sample, inoperable sampler, lost TLD, or
anomalous measurement for the cause and corrective actions and conducted a review
of the licensees assessment of any positive sample results (i.e., licensed radioactive
material detected above the lower limits of detection (LLDs)).
The inspectors reviewed sampler station modifications since the last inspection and/or
significant changes made by the licensee to the ODCM as dictated by the 2002 or
2003 land use census. The inspectors reviewed technical justifications for changed
sampling locations. The inspectors verified that the licensee performed the reviews
required to ensure that the changes did not affect its ability to monitor the impacts of
radioactive effluent releases on the environment.
24 Enclosure
The inspectors reviewed the calibration and maintenance records for all indicator,
control and special environmental air samplers, focusing on the air flow meter and
particulate filter/charcoal cartridge components. Additionally, records of the most recent
full calibration for each of the two field rotameters and for the master rotameter used by
the licensee to measure and validate air sample pump flow rates was reviewed to
ensure traceability to the National Institute of Standards and Technology. As the
licensee does not conduct analyses of REMP samples on-site and utilizes a vendor
laboratory to provide analytical services, the inspectors did not review licensee
calibration records for environmental sample radiation measurement instrumentation
(i.e., count room equipment) or quality control charts.
The inspectors reviewed the results of the REMP sample vendors quality control
program including the inter-laboratory comparison program to verify the adequacy of the
vendors program and the corrective actions for any identified deficiencies. The
inspectors reviewed the LLD values achieved by the vendor laboratory for all REMP
required sample media to verify that analytical detection capabilities met ODCM
requirements for each environmentally monitored pathway. The inspectors reviewed the
report of the last quality assurance audit of the radiological environmental monitoring
program to determine whether the licensee met its TS/ODCM requirements.
These reviews represented six inspection samples.
b. Findings
No findings of significance were identified.
.3 Unrestricted Release of Material from the Radiologically Controlled Area (RCA)
a. Inspection Scope
The inspectors observed locations where the licensee typically monitors potentially
contaminated material and individuals leaving the RCA, and evaluated the procedures
and practices used for control, survey, and release of materials and workers from these
areas. The inspectors questioned several radiation protection staff responsible for the
performance of personnel surveying and releasing material for unrestricted use to
assess their knowledge of procedures and protocols and to verify that release surveys
are performed appropriately.
The inspectors assessed the radiation monitoring instrumentation used for both the
unrestricted release of workers and material/equipment from the RCA, to determine if it
was appropriate for the radiation types present and was calibrated with radiation
sources consistent with the plants nuclide mix. The inspectors reviewed the licensees
criteria for the survey and release of potentially contaminated material and workers to
verify that there was guidance on how to respond to an alarm which indicates the
potential presence of licensed radioactive material. The inspectors reviewed the
licensees radiation survey equipment to ensure the radiation detection sensitivities were
consistent with the NRC guidance for surface contamination contained in Circular 81-07,
Control of Radioactively Contaminated Material, and Information Notice 85-92, Survey
of Wastes Before Disposal from Nuclear Reactor Facilities, and with Health Physics
25 Enclosure
Positions (position-221) in NUREG/CR-5569 for volumetrically contaminated material.
The inspectors reviewed the licensees program to determine if it adequately identified
and evaluated the impact of difficult-to-detect radionuclides (i.e., those that decay via
electron capture) and accounted for those nuclides during routine unrestricted release
surveys. The inspectors reviewed the licensees procedures and records to verify that
the radiation detection instrumentation was used at its typical sensitivity level based on
appropriate counting parameters (i.e., counting times and background radiation levels).
The inspectors verified that the licensee had not established a release limit by altering
the instruments typical sensitivity through such methods as raising the energy
discriminator level or locating the instrument in a high radiation background area.
Additionally, the inspectors reviewed the circumstances associated with the
unconditional release of a workers contaminated boot in September/October 2002, that
was subsequently identified when the worker attempted to leave the Braidwood Nuclear
Station approximately 1 year later wearing those boots. Specifically, the inspectors
reviewed the licensees condition evaluation of the incident, reviewed radiation
protection (RP) procedures governing the unconditional release program, and discussed
the incident with RP staff. The inspectors also independently performed a dose
assessment to verify the adequacy of the occupational dose assigned to the worker that
wore the contaminated boot.
These reviews represented two inspection samples.
b. Findings
Introduction: A self-revealed finding of very low safety significance which involved a
Non-Cited Violation was identified for the failure to conduct an adequate radiological
survey of a workers footwear following a contamination monitor alarm, prior to its
unconditional release from the RCA. As a result, the licensee failed to detect a discrete
radioactive particle (DRP) embedded in a boot worn by a worker which allowed the
contaminated boot to be released unconditionally without any radiological restrictions.
Description: On October 16, 2003, a contract worker alarmed the portal radiation
monitor at the gatehouse upon attempting to depart the Braidwood Nuclear Station. The
cause of the alarm was later determined to be a DRP comprised primarily of cobalt-60
that was embedded (fixed) on the upper exterior portion of the individuals work boot.
The individual had not entered any RCAs since starting work at Braidwood 3 days
earlier and had not worked at a nuclear plant since October 2002. In September and
October 2002, the individual worked at the Dresden Station during their refueling outage
and was involved in reactor assembly/disassembly. The boots were worn exclusively for
work at nuclear plants and remained at the individuals residence when not being used.
An investigation by Dresden RP staff revealed that the individual had contaminated his
boots twice while at Dresden Station (September 18 and October 25, 2002) but was
allowed to leave the site with the boots after they were decontaminated and hand
surveyed by RP staff, and the worker subsequently cleared the personal contamination
monitor (PCM) at the RCA egress. The boots had remained at the station during the
individuals employment tenure at Dresden and were hand carried through the
gatehouse portal monitors on the workers final day onsite on October 25, 2002. Due to
26 Enclosure
the location and the quantity (90 nanocurie maximum) of radioactive material on the
workers boot and the type of radiation monitors used at Dresdens RCA and plant
egress locations, the DRP was probably not detected by these automated monitors.
Based on the licensees evaluation and the inspectors independent assessment of the
problem, the contaminated boot escaped detection by the licensee primarily because
the RP staff failed to conduct a thorough survey (hand-held instrument frisk) on one or
both of those occasions when the worker alarmed the automated PCM at the RCA
egress. Following a survey (frisk) of the worker and decontamination of the workers
boots by the RP staff, the worker was allowed to leave after successfully clearing a
PCM. The embedded DRP probably escaped detection by the PCM due to the type of
detectors used at the RCA egress and the location of the particle relative to the detector
geometry. The PCMs located at the contractor RCA egress used by the worker were
sensitive to beta-emitting radioactive material only and lacked gamma-sensitivity. The
DRP likely escaped gatehouse portal monitor detection because the worker hand-
carried the boots through the monitor in a less than optimal detection configuration.
Analysis: The inspectors determined that the licensee failed to conduct an adequate
survey following PCM alarms. As a result, the licensee did not detect a DRP that was
embedded on the workers boot. This failure represents a performance deficiency. The
inspectors determined that the issue was associated with the Program and Process
and Human Performance attributes of the Public Radiation Safety Cornerstone and
affected the cornerstone objective to ensure adequate protection of the public health
and safety from exposure to radioactive materials released into the public domain. Also,
the issue involved an occurrence in the licensees radioactive material control program
that was contrary to NRC regulations. Therefore, the occurrence represents a more
than minor issue which was evaluated using the significance determination process
(SDP) for the Public Radiation Safety Cornerstone.
The inspectors determined that the licensee failed to prevent the inadvertent release
and loss of control of licensed material outside the protected area that could have
potentially caused radiation dose to the public. Utilizing Manual Chapter (MC) 0609,
Appendix D, Public Radiation Safety SDP, the finding involved radioactive material
control but did not involve transportation, public radiation exposure was not greater than
0.005 rem total effective dose equivalent (TEDE) and the licensee did not have more
than five radioactive material control occurrences in the previous eight quarters. Based
on both the licensees and the inspectors independent dose assessments, the DRP did
not result in a TEDE dose (as defined in 10 CFR Part 20) to either the worker or a
member of the public greater than one mrem. Therefore, consistent with Section VI of
Appendix D to MC 0609, the finding is not suitable for SDP evaluation. The extremity
(foot) dose determined for the worker was conservatively calculated at 500 mrem or one
percent of the occupational dose limits of 10 CFR 20.1201. Based on the lack of public
dose consequence and the magnitude of the occupational dose to the worker, the
finding is determined to be of very low safety significance.
Enforcement: Title 10 CFR 20.1501 requires, in part, that surveys be made as
necessary to comply with the requirements of 10 CFR Part 20 to evaluate the quantities
of radioactive material, the magnitude of radiation levels, and the potential radiological
hazards. Subpart I of 10 CFR Part 20, Storage and Control of Licensed Material, and
27 Enclosure
specifically 10 CFR 20.1802 require that licensed material in an unrestricted area that is
not in storage be controlled. However, between September 18 and October 25, 2002,
the licensee failed to conduct adequate followup surveys of a worker that alarmed PCMs
upon attempting to leave the RCA. As a result, a DRP was released into the public
domain where it remained uncontrolled until detected at the Braidwood Station
approximately 1 year later. The failure to conduct adequate surveys following PCM
alarms is a violation of 10 CFR 20.1501 which led to a violation of 10 CFR 20.1802. The
finding is not suitable for SDP evaluation, but has been reviewed by NRC management
and is determined to be a Green finding of very low safety significance.
The licensee performed an apparent cause evaluation of this event, assessed the dose
to the worker and implemented adequate corrective action. These corrective actions
included tailgate training to radiation protection staff that respond to contamination
monitor alarms, improvements to RCA automated radiation monitors used at the main
RCA egress location via the installation of new gamma-sensitive monitors, and actions
to enhance gamma-sensitivity of those radiation monitors located at alternate RCA
egresses and at the gatehouse. Since the licensee documented this issue in its
corrective action program (condition report (CR) 181692) and because the violation is of
very low safety significance, its is being treated as a Non-Cited Violation.
(NCV 05000237/2004010-05; 05000249/2004010-05).
.4 Identification and Resolution of Problems
a. Inspection Scope
The inspectors reviewed the licensees self-assessments, audits and Special Reports,
as applicable, related to the radiological environmental monitoring and radioactive
material control programs 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 self-assessment and/or audit program was capable of
identifying repetitive deficiencies or significant individual deficiencies in problem
identification and resolution.
The inspectors also reviewed CRs related to the REMP and the radioactive material
control program since the previous inspection, 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.
28 Enclosure
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES (OA)
4OA1 Performance Indicator Verification (71151)
.1 Initiating Events and Mitigating Systems
a. Inspection Scope
The inspectors reviewed a sample of plant records and data against the reported
Performance Indicators in order to determine the accuracy of the indicators:
Unit 2:
- Heat Removal (Low Pressure Coolant injection/Containment Cooling Service
Water), July 2003 - 2004
- High Pressure Coolant Injection, September 2003 - 2004
- Emergency AC Power System, April 2003 - September 2004
- Safety System Functional Failure, July 2003 - September 2004
Unit 3:
- Heat Removal (Low Pressure Coolant injection/Containment Cooling Service
Water), July 2003 - 2004
- High Pressure Coolant Injection, September 2003 - 2004
- Emergency AC Power System, April 2003 - September 2004
- Safety System Functional Failure, July 2003 - September 2004
b. Findings
No findings of significance were identified.
Cornerstone: Public Radiation Safety
.2 Radiation Safety Strategic Area
a. Inspection Scope
The inspectors sampled licensee submittals for the performance indicator (PI) listed
below for the period indicated. To verify the accuracy of the PI data reported during that
period, PI definitions and guidance contained in Revision 2 of Nuclear Energy Institute
Document 99-02, Regulatory Assessment Performance Indicator Guideline, were
used. The following PI was reviewed:
29 Enclosure
- Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent
Occurrence PI
The inspectors reviewed the licensees assessment of this PI by reviewing CRs
generated during approximately the 18 months preceding the inspection to identify any
potential occurrences such as unmonitored or improperly calculated effluent releases
that could have impacted offsite dose. Also, the inspectors evaluated the licensees
methods for determining offsite dose from radiological effluents and reviewed monthly
PI data elements for the April 2003 through June 2004 period to verify that data was
recorded and verified as required by the licensees PI procedure.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
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
accomplished by reviewing daily condition reports and attending daily condition report
review meetings.
b. Findings
No findings of significance were identified.
4OA3 Event Follow-up (71153)
a. Inspection Scope
The inspectors reviewed licensee event reports (LERs) to ensure that issues
documented in these reports were adequately addressed in the licensees corrective
action program. The inspectors also interviewed plant personnel and reviewed
operating procedures to ensure that generic issues were captured appropriately.
The inspectors reviewed the Updated Final Safety Analysis Report and other documents
to verify the statements contained in the LERs.
30 Enclosure
a. Findings
.1 (Closed) LER 50-237;249/2004-003-00: Unit 2 and 3 Control Room Emergency
Ventilation System Inoperable Due To Damper Failure to Close
Introduction: Two Green findings were identified during the review of
LER 50-237;249/2004-003. The first was a Green self-revealing finding involving the
failure to restore the control room emergency ventilation (CREV) system to operable
status following maintenance. This resulted in a NCV of TS 3.7.4 , CREV System,
Action Statement A.1. This finding was considered to be self-revealing because it was
discovered when the system did not operate properly during routine realignment from
train A to train B.
The second was a Green NRC identified finding involving failure to control parts and
equipment necessary for the performance of a post accident procedure to maintain
control room habitability in the event of a failure of train B of control room ventilation.
This finding was considered to be NRC identified because, when the inspector was
doing an in-plant walk-down of an operating procedure that had been modified as a
corrective action for this LER, the inspector found that necessary parts were not being
controlled as called for in the procedure.
Discussion: The Unit 2 and 3 control room heating ventilation and air conditioning
(HVAC) system has two trains, A and B. Normally, control room ventilation is supplied
by train A. The CREV system is used to protect control room personnel in the event of
high outside airborne radioactive contaminants, outside toxic gases, and to purge
smoke from the control room in the event of an internal fire. Following a loss of coolant
accident (LOCA), the normal outside air intake is isolated and outside air is supplied
thought an air filtration unit (AFU) containing high efficiency particulate filters and
charcoal adsorbers. Analysis has shown that as long as the control room outside air
supply is switched to the AFU within 40 minutes of a LOCA, control room operator doses
will remain within limits.
On April 19, 2004, a temporary modification was installed on the CREV system to allow
operation of train A HVAC while preventive maintenance (PM) was being performed on
a 480 Volt breaker. While the PM was being performed, control power to solenoid
valves that supply pneumatic air to position CREV isolation dampers would be lost.
Without control power the CREV dampers would fail closed and control room ventilation
would be unavailable. The temporary modification provided pneumatic jumpers, (plugs
for the solenoid valve exhaust ports and temporary tubing that bypassed the solenoid
valves) to maintain the CREV isolation dampers open. With the temporary modification
in place the CREV system was declared inoperable on a 7 day time clock.
On April 22, 2004, with the breaker PM completed, a work order to remove the
temporary modification was completed, and the CREV system was tested and declared
operable. On April 28, 2004, a routine realignment of the control room HVAC from
train A to B was attempted. During this realignment the HVAC damper for the unfiltered
air supply should have closed but remained open. With the unfiltered air supply damper
failed open, protection from external airborne radioactivity and toxic gas was
unavailable. The CREV system was again declared inoperable and troubleshooting was
31 Enclosure
initiated. It was found that the temporary modification that had been installed on
April 19, 2004, had only been partially removed on April 22, 2004. The temporary tubing
that bypassed the solenoid valves had been removed but the plugs in the solenoid valve
exhaust ports had been left installed. Therefore, the CREV system had been inoperable
for greater than 7 days from April 19 until April 28, 2004, in violation of TS 3.7.4.
On August 3, 2004, the inspectors conducted an in-plant walkdown of procedure
DOA 5750-01, VENTILATION SYSTEM FAILURE, Revision 37. This procedure
contained instructions for the installation of the temporary modification for placement of
the pneumatic jumpers to maintain the CREV isolation dampers open. This procedure
was revised as a corrective action resulting from this LER. The inspectors walked down
this procedure because it called for installation of the temporary modification, following a
LOCA and failure of the train B air handling unit, to restore control room ventilation.
Procedure DOA 5750-01 called for this to be completed within 40 minutes of the LOCA
in order to maintain control room radiation dose within limits. The complexity of the
procedure made the inspector question if it could be completed in the required time.
The procedure is written assuming jumpers, pipe plugs, fittings, and wrenches are pre-
staged in the control room Dresden Emergency Operating Procedures (DEOP) Cabinet.
When asked, neither of the two control room Unit Supervisors were able to locate the
pre-staged equipment for inspection. With the help of the NRC inspector the equipment
was located in a miscellaneous equipment drawer of the DEOP Cabinet, the jumper
tubes were lying loose and unmarked, the fittings were in two plastic bags labeled with
black felt tip marker Temp Alt 5-10-99," and no hexagonal-end wrench was available to
install the required pipe plugs. The inspector concluded that had it been necessary to
install the temporary modification and restore control room ventilation following a LOCA
it may have taken more than the allotted 40 minutes.
Analysis: For the self-revealing finding involving the violation of TS 3.7.4, Action
Statement A.1, the licensee determined that the root cause of the failure to completely
remove the temporary modification from the CREV system was inadequate instructions
in procedure DOA 5750-01, Ventilation System Failure, in that guidance for removal
was not included in the procedure. Using IMC 0612, Appendix B, Issue Screening, the
inspector determined that the failure to return the CREV system to operable status
within its TS allowed outage time was a performance deficiency. The inspectors
concluded that this issue was more than minor because it affected the Reactor Safety
Barrier Integrity Cornerstone design control and configuration control attributes, and the
objective of protecting persons in the control room from radionuclide releases caused by
accidents or events.
Using IMC 0609, Appendix A, Significance Determination of Reactor Inspection
Findings for At-Power Situations, dated September 10, 2004, the inspector answered
No to question one in the Containment Barriers column of the Phase 1 worksheet of
the SDP worksheet in that not only was the radiological barrier function for the control
room effected but also the barrier against toxic atmosphere. For the same reason
question number one was answered No, question two was answered Yes which
required a Phase 3 SDP analysis.
The finding was referred to the SRA for a Phase 3 analysis. The analyst consulted with
licensee risk specialists to gain an understanding of the potential sources for toxic gas
32 Enclosure
intrusion into the control room. These sources included onsite sources, especially those
that might be deployed on the roof areas near the outside air intake and chemical plants
or refineries in the vicinity of the plant. The principal risk to core damage would be
debilitation of the control room operators or a forced evacuation requiring alternate
means to achieve a safe shutdown. Based on a qualitative judgement of the
unlikelihood of toxic gas reaching the outside air intake in sufficient concentrations to
affect operators in combination with the short exposure period of the finding (6 days),
the analyst concluded that the finding was of very low risk significance (Green).
The second finding, that the licensee had failed to control parts and equipment
necessary for the performance of a post accident procedure to maintain control room
habitability, was also evaluated using IMC 0612, Appendix B, Issue Screening. The
inspectors concluded that this issue was more than minor because it also affected the
Reactor Safety Barrier Integrity Cornerstone design control and configuration control
attributes, and the objective of protecting persons in the control room from radionuclide
releases caused by accidents or events. Using IMC 0609, Appendix A, Significance
Determination of Reactor Inspection Findings for At-Power Situations, the finding
screened as very low safety significance (Green). This was due to the inspector
answering Yes to question number one in the Containment Barriers column of the
Phase 1 worksheet of the SDP worksheet, because the uncontrolled equipment would
have only been used to provide the radiological barrier function for the control room
following an accident.
Enforcement: The failure to restore the CREV system to operable status following
maintenance, resulted in a violation of TS 3.7.4. Action Statements B.1 and B.2 require
that if restoration of the CREV system to operable status is not complete in 7 days, the
plant is to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Mode 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Contrary to the
above, the licensee failed to properly remove a temporary modification to the CREV
isolation dampers, which resulted in the CREV system being inoperable for 9 days from
April 19, 2004, to April 28, 2004. Believing the system had been restored to an operable
status on April 22, 2004, the licensee failed to take the appropriate actions dictated by
T.S. 3.7.4, Action Statements B.1 and B.2. The licensee revised the procedure to give
better guidance on how to remove the temporary modification. Because this issue is of
very low safety significance and has been entered into the licensees corrective action
program as Condition Report 217741, this violation is being treated as a Non-Cited
Violation, consistent with Section VI.A., of the NRC Enforcement Policy.
(NCV 05000237/2004010-06; 05000249/2004010-06)
The failure to control parts and equipment needed for the performance of a post
accident procedure to maintain control room habitability in the event of the failure of
train B of control room ventilation was not considered a violation of regulatory
requirements. This was because, although procedures call for the use of CREV train A
in the event of a train B failure, the finding involved non-safety related equipment. The
licensee entered this issue into the stations corrective action program as CR 242461.
The licensee identified a number of corrective actions including properly packaging the
necessary parts and tools, revising procedures DOA 5750-01 and 5750-04, and initiating
a training request to ensure operations personnel are properly trained in the use of the
33 Enclosure
DOA air jumpers. This issue was considered a finding of very low significance.
(FIN 05000237/2004010-07; 05000249/2004010-07)
.2 (Closed) LER 50-237/2004-004-00 and LER 50-237/2004-004-01: Unit 2 Manual Scram
Due To The Trip Of A Reactor Recirculation Pump
Introduction: A Green self-revealed finding was identified involving several performance
issues which resulted in the initiation of a manual scram. The performance issues
included an inadequate process for rewinding the 2A recirculation pump motor when it
was installed in 1999, an inadequate evaluation of the testing of the motor before
installation, and the failure to perform post maintenance testing of the reactor building
closed cooling water (RBCCW) system piping to identify leakage. This failure resulted
in the deposit of a conductive substance inside the motor.
Description: On April 24, 2004, with Unit 2 at 66 percent power, the 2A reactor
recirculation pump tripped when a short between phases A and B of the motor winding
occurred. Operators initiated a manual scram in accordance with Dresden Abnormal
Procedure DOA 202-01, Recirculation (RECIRC) Pump Trip - One Or Both Pumps,
Revision 25. The plant was in a region of the reactors power to flow map that required
an immediate manual scram. All plant systems responded normally to the scram.
The licensee initiated a root cause investigation which identified that on
October 10, 1999, during the Unit 2 refueling outage, the 2A reactor recirculation pump
motor was replaced. This motor was originally sent to the vendor for rewind and testing
in March of 1997.
In June 1999, during the testing of the rewound spare motor, inadequately sealed spots
at the series connections location at the lower end of the motor were identified. A repair
was initiated and the test was completed satisfactorily. However, the licensee did not
evaluate or determined the cause at that time of the deficiency. The licensees root
cause report stated that this condition may have indicated a potential weak spot that
would have required a full repair.
During the replacement of the motor, the RBCCW piping was reconnected to the
rewound motor. However, post maintenance testing was not performed to ensure the
piping and fittings did not leak. Following the refuel outage, in October 2001, the
licensee identified a RBCCW water leak in an elbow in a lower air intake of the 2A
recirculation pump motor. The leak was from a loose pipefitting. This condition had
resulted in the presence of electrically conductive surface deposits and moisture
intrusion onto the motor winding. Subsequently, this deficiency contributed to the failure
of the connection points insulation and the motor failure.
A failure analysis was conducted by the vendor which concluded that the motor failure
was attributed to the presence of moisture, conductive surface contamination, and weak
spots in the insulation of the series connections due to a voltage and mechanical stress
concentration point at the end of the conductor.
34 Enclosure
Based on the licensees determination of the root cause and contributing causes, one
Green finding was identified involving performance issues which resulted in the initiation
of a manual scram. The performance issues included an inadequate process for
rewinding the 2A recirculation pump motor when it was installed in 1999, an inadequate
evaluation of the testing of the motor before installation, and the failure to perform post
maintenance testing of the RBCCW system piping to identify leakage. This failure
resulted in the deposit of conductive substance inside the motor.
Analysis: Using IMC 0612, Appendix B, Issue Screening, the inspectors determined
that this finding was more than minor because it affected the initiating events
cornerstone objective to limit the likelihood of an initiating event. The inspectors
completed a significance determination of this issue using IMC 0609, Appendix A,
Significance Determination of Reactor Inspection Findings for At-Power Situations.
The inspectors answered No to all questions in the initiating event column of the
Phase 1 Screening Worksheet; and therefore, concluded that the issue was of very low
safety significance (Green). (FIN 05000237/2004010-08)
Enforcement: No violation of NRC requirements occurred because the finding involved
non-safety related equipment. The licensee entered this issue into the stations
corrective action program as CR 217570. The licensee identified a number of corrective
actions including replacing the failed reactor recirculation pump motor and revising
Exelon Nuclear Engineering Standard NES-EIC-40.01, Revision 1, Large Motor (>2kv)
Repair Requirements, to include enhanced testing requirements
.3 (Closed) LER 50-237;249/2004-003-00: Unit 3 Scram Due to Loss of Offsite Power and
Subsequent Inoperability of the Standby Gas Treatment System for Units 2 and 3
On May 5, 2004, at 1327 hours0.0154 days <br />0.369 hours <br />0.00219 weeks <br />5.049235e-4 months <br />, with Unit 3 at 100 percent power, an automatic scram
occurred due to a main generator load reject when a loss of offsite power occurred. All
systems initially responded to the scram as expected except the standby gas treatment
system was unable to maintain the secondary containment at the TS surveillance
requirement limit of greater than or equal to 0.25 inches of vacuum water gauge. An
Unusual Event for the loss of offsite power was declared at 1342 hours0.0155 days <br />0.373 hours <br />0.00222 weeks <br />5.10631e-4 months <br /> and terminated
at 1601 hours0.0185 days <br />0.445 hours <br />0.00265 weeks <br />6.091805e-4 months <br /> on May 5, 2004. Additionally, during restoration of offsite electrical power
to Bus 33, the emergency diesel generator 2/3 output breaker tripped.
This event was reviewed during an NRC Special Inspection conducted on May 6 through
May 14, 2004, and documented in Special Inspection Report 05000249/2004009 issued
on June 21, 2004. The report documents three self-revealed findings of very low safety
significance (Green). Two of the findings were determined to be violations of NRC
requirements. The first finding, not associated with a violation of NRC requirements,
was related to inadequate preventive and corrective maintenance performed on
switchyard circuit breaker 8-15 which caused the C phase of the breaker to not open
when operated on May 5, 2004. The second finding, associated with a violation of NRC
requirements, dealt with inadequate procedures for restoration of offsite power to safety
related busses. The third finding, associated with a violation of NRC requirements dealt
with an inoperable secondary containment when the opposite units drywell purge fans
were in operation.
35 Enclosure
Since the Special Inspection, the licensee completed W.O. 698088 on August 18, 2004,
which implemented the ABB Product Advisory for the remaining gas SF6 circuit
breaker 6-7. In August 2004, the system engineer verified that ABB has provided
Exelon Energy Distribution all applicable product advisories. Dresden Operations issued
Standing Order 04-06 for switchyard activity control which discusses the proper
management of work occurring in the Dresden switchyards.
Exelon Nuclear has established an executive committee, which includes representatives
from Exelon Energy Delivery, to enhance the reliability of its nuclear station switchyards.
A significant outcome of this initiative will be the development of preventative
maintenance templates for the various switchyard components. The licensee expects
full implementation of the templates at Dresden by June 30, 2005. In addition, an
Exelon liaison position has been established for industry switchyard issues.
The cause of the emergency diesel generator output breaker trip was still under
investigation at the time of the LER submittal. The final corrective actions for the
breaker trip will be described in a supplemental report scheduled to be submitted no
later than October 30, 2004.
.4 (Closed) LER 50-249/2004-004-00: Unit 3 Shutdown due to Inoperable Source Range
Monitor
On May 8, 2004, at 0229 hours0.00265 days <br />0.0636 hours <br />3.786376e-4 weeks <br />8.71345e-5 months <br />, with Unit 3 subcritical during startup in Mode 2, source
range monitor (SRM) 24 was declared inoperable due to erratic indications. SRM 22
was already inoperable due to the inability to fully insert the detector into the core
region. This resulted in the plant being unable to meet the TS 3.3.1.2, SRM
Instrumentation, requirement of three operable SRMs in Mode 2. A reactor shutdown
was commenced at 0450 hours0.00521 days <br />0.125 hours <br />7.440476e-4 weeks <br />1.71225e-4 months <br />. All control rods were fully inserted in the reverse order
in which they had been withdrawn, and the plant entered Mode 3 at 0535 hours0.00619 days <br />0.149 hours <br />8.845899e-4 weeks <br />2.035675e-4 months <br />.
The licencee determined that SRM 22 had a faulty full-in limit switch. The limit switch
was replaced. SRM 24 was inoperable due to an oxide buildup on the connectors. The
connectors were disconnected and reconnected numerous times, stopping the erratic
indication during troubleshooting. A work request was written to thoroughly clean all the
connectors during the next refueling outage. Engineering will evaluate the need for a
preventive maintenance item to periodically clean the SRM connectors and evaluate the
potential of refurbishing the limit switch and a replacement frequency. No findings were
identified.
.5 (Closed) LER 50-237/2004-002-00: Unit 2 SCRAM Due to Main Steam Isolation Valve
Closure and Subsequent Inoperability of the Isolation Condenser
Introduction: A violation of 10 CFR 50, Appendix B, Criterion V, of very low safety
significance (Green) was self-revealed during the recovery from a reactor scram on
April 24, 2004. Licensee maintenance personnel failed to correctly set the open torque
switch bypass setting for motor operated Valve (MOV) 2-1301-3, Isolation Condenser
Outboard Condensate Return Valve, on October 8, 1999. This resulted in the failure of
Valve 2-1301-3 to open when an operator tried to manually operate the valve from the
control room.
36 Enclosure
Description: On October 8, 1999, two electrical maintenance personnel performed
procedure DEP 0040-10, MOV Votes Test Procedure, Revision 13, in accordance with
Work Order 97071725-01. Procedure DEP 0040-10, Attachment C, Step 30, stated,
Verify limit switch settings are correct and that on four rotor models the Open Torque
Switch Bypass opens at 50 percent to 70 percent of the full open stroke. Valve 2-1301-
3 was a gate valve with a 12 inch full mechanical stroke. Because of the valves
function, the licensee determined that the full electrical stroke should only be
1.65 inches. The electrical maintenance personnel set the open torque switch bypass
at .975 inches per the procedure. However, Step E.6 stated, Verify the limits are set
per the MOV Set Point Binder using the VOTES trace and to adjust as necessary, and
Step G.5.F, stated, Verify limit switch settings comply with the Set Point Binder, if
adjustments have to be made refer to DEP 040-09, Limitorque Valve Operator
Maintenance. Both of these steps were signed off as complete. The MOV Set Point
Binder had the correct open torque switch bypass setting of 4.5 inches which was
beyond the valves electrical open stroke. The licensee concluded that the procedure
was inadequate since it contradicted itself and that human performance was a
contributing cause. The inspectors agreed with the licensees conclusions. The
procedure was misleading; however, had the technicians read the MOV Set Point Binder
and saw the discrepancy the problem could have been resolved.
Analysis: The inspectors determined that the failure to adequately set the open torque
switch bypass setting for Valve 2-1301-3 was a performance deficiency warranting a
significance evaluation. The inspectors concluded that the finding was more than minor
in accordance with IMC 0612, Appendix B, Issue Screening, dated June 20, 2003.
The inspectors determined this was more than minor because it affected the
configuration control, equipment performance, and procedure quality attributes of the
mitigating systems cornerstone and the cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences.
The inspectors completed a significance determination of this issue using IMC 0609,
Appendix A, Significance Determination of Reactor Inspection Findings for At-Power
Situations, dated September 10, 2003. For the Phase 1 analysis the inspectors
answered questions 1 and 2, Yes under the mitigating systems cornerstone column.
This resulted in the required performance of a Phase 2 analysis. The inspectors
reviewed worksheet tables for the following: Transients, Transients without Primary Heat
Sink, Loss of Service Water, Loss of Instrument Air, Loss of An AC [alternating current]
Bus, and Loss of Offsite Power. The inspectors assumed that 1) the isolation
condenser was unavailable from the beginning of each transient, and 2) that the
isolation condenser valve could not be recovered. Base on these two assumptions,
using the counting rule, worksheet step 13 was greater than zero which initially had a
risk significance of Yellow. The inspectors realized that the assumptions made to
perform the Phase 2 were inaccurate. The evaluation was sent to the Regional Office in
order to perform a Phase 3 analysis. The Phase 3 analysis performed by the Senior
Reactor Analyst (SRA) concluded that the safety significance of this finding based on
the change in core damage frequency was Green. The Phase 3 analysis reviewed the
potential failure probabilities based on the procedure and equipment inadequacies.
37 Enclosure
Enforcement: The failure to have adequate instructions for work involving a safety-
related valve resulted in a violation of 10 CFR 50, Appendix B, Criterion V. Code of
Federal Regulations Title 10, Part 50, Appendix B, states in part, Activities affecting
quality shall be prescribed by documented instructions, procedures, or drawings, of a
type appropriate to the circumstances... The setting of the open torque switch bypass
on Valve 2-1301-3 was an activity affecting quality. Contrary to the above, on
October 8, 1999, the open torque switch bypass was set improperly on Valve 2-1301-3
due to inadequate procedural guidance. Because this issue is of very low safety
significance and has been entered into licensees corrective action program
(IR 216787), this violation is being treated as a Non-Cited Violation, consistent with
Section VI.A., of the NRC Enforcement Policy. (NCV 05000237/2004010-09)
.6 (Closed) LER 50-237;249/2004-005-00: Units 2 and 3 Inoperable Turbine Condenser
Vacuum - Low Switches
Introduction: The inspectors identified a NCV of TS 3.3.1.1 having a very low safety
significance (Green) for failing to properly enter a required TS LCO when the 3C and 2A
turbine main condenser low vacuum Reactor Protection System (RPS) scram channels
were inoperable. This issue was considered to be NRC-identified because the licensee
had failed to identify this deficiency without the inspectors questions on July 1, 2004.
The licensee looked into the issue further and identified that these switches had been
inoperable outside their TS outage time multiple times in the past 2 years. Had it not
been for the inspectors questioning, the licensee would not have found the problem at
this particular time. Therefore, the finding is considered inspector identified.
Description: On April 5, and May 3, 2004, vacuum indication taken from the 3C main
condenser hood was not indicating accurate values after circulating water flow was
reversed. Subsequent trending activities by the system engineer revealed that the
vacuum indication from the 2A condenser hood was also exhibiting bad vacuum
indication on some occasions after flow reversals.
The low condenser vacuum pressure switches provided reactor scram signals to protect
the reactor from loss of the main heat sink. Protection for the condenser itself was
assured by closure of the turbine stop and bypass valves as vacuum decreases below a
preset low level. Condition Report (CR) 218325 dated May 1, 2004, Condenser
Vacuum Indication Error Caused by Condensation, stated that the 3C condenser low
vacuum reading was inaccurate. The error caused a measured vacuum that was higher
than the actual value; and therefore, farther away from the trip setpoint. The cause of
the inaccurate vacuum indication was attributed to improperly sloped sensing lines and
water accumulation. The sensing lines connected vacuum instrumentation to the
condenser hoods. The RPS trip switches utilized the same sensing lines as the control
room indication and plant process computer points.
Operations personnel failed to recognize that the 3C switch was inoperable. At the time
of discovery, the switch had already been inoperable for a time greater than the TS
allowed completion time. At the time of discovery operations personnel took appropriate
actions and restored the channel to an operable status within the TS LCO.
38 Enclosure
The inspectors discussed the Unit 3 main condenser vacuum sensing line operability
evaluation with system engineering personnel and were able to obtain historical data
that demonstrated that the 3C and 2A pressure switches were inoperable for greater
than their allowable outage time at least four times in the past 2 years. The licensee
agreed that periods of longer than the TS LCO allowed completion time were exceeded.
The licensees root cause report stated that on some occasions, initial interaction
between plant engineering and the operations personnel failed to identify vacuum
indication instrumentation as inoperable. The licensee attributed these failures to
weaknesses in the operations training materials with regard to the inter-relations
between the RPS pressure switches and the control room recorder. The licensee also
identified weaknesses in the operator rounds appendices and procedures. Specifically,
the operations flow reversal procedure, DOP 4400-08, Revision 33, Circulating Water
System Flow Reversal, did not include information to tell operators what to observe
relative to hood vacuum following a circulating water flow reversal. Finally, the root
cause report identified a weakness in the corrective action program, in that previous
corrective actions from Licensee Event Report (LER) 249/98006 for a similar issue were
too narrowly focused and did not correct the problem.
Analysis: The inspectors determined that the failure to take adequate corrective actions
to prevent recurrence of inoperable low vacuum RPS switches, failure to recognize the
switches were inoperable, and failure to enter the appropriate TS LCO were
performance deficiencies warranting a significance evaluation. The inspectors
concluded that the finding was more than minor in accordance with IMC 0612, Appendix
B, Issue Screening, dated June 20, 2003. The inspectors determined that this finding
was more than minor because it affected the mitigating systems cornerstone design
control and equipment performance attributes, and the objective of ensuring the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. The inspectors completed a significance
determination of this issue using IMC 0609, Appendix A, Significance Determination of
Reactor Inspection Findings for At-Power Situations, dated September 10, 2004. The
inspectors answered No to all questions in the mitigating systems column of the
Phase 1 Screening Worksheet; and therefore, concluded that the issue was of very low
safety significance (Green). This finding was associated with the reactor safety
cross-cutting attribute of Problem Identification and Resolution.
Enforcement: Technical Specification 3.3.1.1, Reactor Protection System (RPS)
Instrumentation, Condition A, stated that if one or more required channels were
inoperable, place the channel in trip within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to the above, the licensee
failed to enter the TS required action within the 12-hour allowable outage time when the
3C and 2A turbine main condenser low vacuum RPS scram channels were inoperable,
which caused an indicated vacuum value that was greater than the actual value; and
therefore, farther away from the trip limit. This occurred on four separate occasions
between 2002 and 2004. The licensees corrective actions, as described in the root
cause report, included installing temporary vent valves on the 3C and 2A sensing lines
to continuously purge and clear condensation from the lines, enhancing operations
training materials to include adequate level of detail on main condenser vacuum
indications, revising the operations procedure DOP 4400-08, Revision 33, Circulating
Water System Flow Reversal, and performing internal and external condenser
39 Enclosure
walkdowns during the next outage on Unit 2 and Unit 3 to determine the sensing line
slope and to repair the sensing line slope, if necessary. Because this issue is of very
low safety significance and has been entered into the licensees corrective action
program as Condition Report 234361, this violation is being treated as a Non-Cited
Violation, consistent with Section VI.A., of the NRC Enforcement Policy.
(NCV 05000237/2004010-10; 05000249/2004010-10)
4OA4 Cross-Cutting Findings
.1 A finding described in 1R06 of this report had, as its primary cause, a Problem
Identification and Resolution deficiency, in that weaknesses had been previously
identified by the NRC with the external flooding surveillance and operating procedures.
.2 A finding described in Section 1R12 of this report had, as its primary cause, a Problem
Identification and Resolution deficiency, in that two functional failures of the reactor
building ventilation system occurred and were not properly entered into the corrective
action program which resulted in the failure to move the reactor building ventilation
system from 10 CFR 50.65 a(2) to a(1).
.3 A finding described in Section 1R20 of this report had, as its primary cause, a Human
Performance deficiency, in that operators failed to perform a return to service clearance
checklist as written. The operators failed to lock open the 2-220-57B main feedwater
isolation valve when it was returned to service.
.4 A finding described in 40A3 of this report had, as its primary cause, a Problem
Identification and Resolution deficiency, in that 1) the licensee failed to correct
equipment deficiencies which resulted in one channel of main condenser low vacuum
reactor trip signals being inoperable on both units after it had been identified as a
problem in 1998; and 2) operations personnel failed to identify that the main condenser
vacuum low pressure switches were inoperable on multiple occasions from 2002 to
2004.
4OA5 Other Activities
(Closed) Unresolved Item 50-237-97021-01 (DRS); 50-249-97021-01 (DRS): The
inspector had 4 concerns: 1) licensee had inadequate analysis to support UFSAR
statements that the Dresden station could be safely shutdown following a Dresden Dam
failure coincident with a loss of coolant accident (LOCA) in one of the units; 2) licensee
had inadequate analysis to support UFSAR statements that station could be safely
shutdown following a Dresden Dam failure during normal operations using only Class I
systems; 3) ultimate heat sink (UHS) inventory was less than assumed in the Systematic
Evaluation Program (SEP) Safety Evaluation Report (SER); and 4) licensee had
inadequate analysis supporting the assumed Service Water Pump (SWP) performance.
These items were referred by Task Interface Agreement (TIA) for Office of Nuclear
Reactor Regulation (NRR) review. The TIA response stated that the accident scenario
of Concern 1 was beyond design basis and no supporting analysis was needed. Also,
the Current Licensing Basis was codified in the Power Uprate SER of license
amendment 191 to Unit 2 and license amendment 185 to Unit 3. The license
40 Enclosure
amendments and SER were issued December 21, 2001. The Power Uprate SER is
located in ADAMS at accession number ML0135401870. The Power Uprate SER did
not require the Dresden Station to safely shutdown following a Dresden Dam failure
coincident with a LOCA in one of the units. Therefore, Concern 1 is closed. For
Concern 2, the Power Uprate SER stated that the licensee did not need to use only
class I systems to shut down. Therefore Concern 2 is closed. For Concern 3, the TIA
response stated that the licensees planned action of using portable engine-driven
pumps to pump water from the intake and discharge canals was acceptable to
compensate for the reduced UHS inventory assumption since the planned actions were
in the emergency procedure. The Power Uprate SER also stated this was acceptable.
Therefore, Concern 3 is closed. For Concern 4, the TIA response stated that the SWPs
could not be assumed to perform without a supporting analysis. The licensee informed
the inspector that the SWPs would no longer be relied on to function after a dam failure
and changed the UFSAR accordingly. Also, the Power Uprate SER stated that the
licensee did not need to credit the SWP pumps for shutdown; therefore, Concern 4 is
closed. This item is considered closed.
40A6 Meetings
Interim Exit Meetings
Interim exit meetings were conducted for:
- Public radiation safety inspection for radiological environmental monitoring and
radioactive material control with Messrs. D. Bost and D. Wozniak on
July 22, 2004. On July 28, 2004, the inspection results were further discussed in
a telephone conversation with Mr. S. Taylor.
4OA7 Licensee Identified Violation
The following violation of very low safety significance (Green) was identified by the
licensee and is a violation of NRC requirements which met the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited
Violation.
Cornerstone: Public Radiation Safety
Technical Specification 5.4.1 requires that written procedures be established,
implemented and maintained covering the applicable procedures in Regulatory
Guide 1.33, Revision 2, Appendix A, February 1978. Procedures specified in
Regulatory Guide 1.33 include those for radiation surveys and for contamination control,
which are provided, in part, by licensee procedure RP-AA-503, Unconditional Release
Survey Method. The licensees procedure requires that material or equipment not be
released for unrestricted use unless it has no detectable licensed radioactive material.
Contrary to this procedure, two separate incidents occurred in October 2003, when low
level but detectable quantities of licensed radioactive material (contaminated materials)
were identified by radiation protection (RP) staff outside the Radiologically Controlled
Area (RCA) (but inside the protected area). These problems occurred because workers
41 Enclosure
failed to understand requirements for the unconditional release of personal items and
other materials from the RCA, exacerbated by inattentive radiation protection staff. The
occurrences are documented in the licensees corrective action program as
CR 00181367 and CR 00184544. Corrective actions included tailgate training with RP
staff, counseling of involved workers and plans to enhance plant and contractor staff
training along with procedural revisions. These problems are of very low safety
significance because the contamination levels on the items inadvertently released
outside the RCA were very low and consequently of little to no dose consequence. The
contaminated items remained within the licensees protected area; and therefore, are
not counted as occurrences as provided in NRC Manual Chapter 0609, Appendix D,
Public Radiation Safety Significance Determination Process.
ATTACHMENT: SUPPLEMENTAL INFORMATION
42 Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
D. Bost, Site Vice President
D. Wozniak, Plant Manager
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
J. Hansen, Regulatory Assurance Manager
R. Kalb, Chemistry ODCM Coordinator
T. Loch, Supervisor, Design Engineering
M. McGivern, System Engineer
D. Nestle, Radiation Protection Technical Manager
M. Overstreet, Radiation Protection Supervisor
R. Quick, Security Manager
N. Spooner, Site Maintenance Rule Coordinator
B. Surges, Operations Requalification Training Supervisor
B. Svaleson, Maintenance Director
S. Taylor, Radiation Protection Director
NRC
M. Ring, Chief, Division of Reactor Projects, Branch 1
R. Schulz, Illinois Emergency Management Agency
Contractor
A. Lewis, REMP Technician, Environmental Inc., Midwest Laboratory
1 Attachment
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000237/2004010-01 URI USFAR change 50.59 (1R06)05000249/2004010-01
Opened and Closed
05000237/2004010-02 NCV Source of Make-up Water (1R06)05000249/2004010-02
05000237/2004010-03 NCV The Licensee Did Not Move the Reactor
05000249/2004010-03 Building Ventilation System Into the Maintenance Rule
(a)(1) Category (1R12)05000237/2004010-04 NCV Operators Failed to Lock Valve in Unit 2 Drywell (1R20)05000237/2004010-05 NCV Failure to Perform an Adequate Radiological
05000249/2004010-05 Survey Prior to the Unconditional Release of Material
Outside the RCA (Section 2PS3)05000237/2004010-06 NCV The Licensee Failed to Correctly Restore the Control
05000249/2004010-06 Room Emergency Ventilation System to Operable Status
Following Maintenance (4OA3)05000237/2004010-07 FIN The Licensee Did Not Control Tools and Equipment
05000249/2004010-07 Staged to Install a Temporary Modification to Keep the
Control Room Emergency Ventilation System Dampers
Open in the Event of an Accident (4OA3)05000237/2004010-08 FIN Performance Issues Which Resulted in the Initiation of a
Manual Scram on Unit 2 Due to Failure of the 2A
Recirculation Pump Motor (4OA3)05000237/2004010-09 NCV Improperly Set Open Torque Switch Bypass of the
Isolation Condenser Outboard Condensate Return Valve
(4OA3)05000237/2004010-10 NCV Failure to Prevent Recurrence of Inoperable Condenser
05000249/2004010-10 Low Vacuum Reactor Protection System Switches (4OA3)
Closed
50-237;249/2004-003-00 LER Unit 2 and 3 Control Room Emergency Ventilation System
Inoperable Due to Damper Failure to Close
2 Attachment
50-237/2004-004-00 and LER Unit 2 Manual Scram Due to the Trip of a Reactor
50-237/2004-004-01 Recirculation Pump
50-237;249/2004-003-00 LER Unit 3 Scram Due to Loss of Offsite Power and
Subsequent Inoperability of the Standby Gas Treatment
System for Units 2 and 3
50-249/2004-004-00 LER Unit 3 Shutdown Due to Inoperable Source Range Monitor
50-237/2004-002-00 LER Unit 2 Scram Due to Main Steam Isolation Valve Closure
and Subsequent Inoperability of the Isolation Condenser
50-237;249/2004-005-00 LER Units 2 and 3 Inoperable Turbine Condenser Vacuum -
Low Switches
50-237/97021-01 (DRS); URI UFSAR Dam Failure Discrepancies
50-249/97021-01 (DRS)
Discussed
None.
3 Attachment
LIST OF ACRONYMS USED
ABB Asea, Brown, and Boveri
AFU air filtration unit
CFR Code of Federal Regulations
CR Condition Report
CREV control room emergency ventilation
DEOP Dresden Emergency Operating Procedure
DIS Dresden Instrument Surveillance
DOA Dresden Abnormal Operating Procedure
DOP Dresden Operating Procedure
DOS Dresden Operating Surveillance
DRP Division of Reactor Projects
DRP discrete radioactive particle
DRS Division of Reactor Safety
HPCI high pressure coolant injection
HVA heating, ventilation, and air conditioning
IEMA Illinois Emergency Management Agency
IMC Inspection Manual Chapter
IR Issue Report
LCO limiting condition for operation
LER Licensee Event Report
LLD lower limit of detection
LOCA loss of coolant accident
MC Manual Chapter
MOV motor operated valve
MWe megawatts electrical
NCV Non-Cited Violation
NRC Nuclear Regulatory Commission
NRR Office of Nuclear Reactor Regulation
OA Other Activities
ODCM Offsite Dose Calculation Manual
PCM personnel contamination monitor
PM preventive maintenance
PMF probable maximum flood
PI Performance Indicator
RBCCW reactor building closed cooling water
REMP Radiological Environmental Monitoring Program
RCA radiologically controlled area
RP radiation protection
SDP Significance Determination Process
SEP Systematic Evaluation Program
SER Safety Evaluation Report
SRA Senior Reactor Analyst
SRM source range monitor
SWP service water pump
TEDE total effective dose equivalent
Attachment
TER Technical Evaluation Report
TIA Task Interface Agreement
TLD thermoluminescence dosimeter
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
WO Work Order
5 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 2300-01, High Pressure Coolant Injection (HPCI) System Standby Operation,
Rev. 28
Unit 2/3, DOP 7500-M1/E1, Unit 2/3 Standby Gas Treatment Valve Checklist, Rev. 05
DOP 1500-M1, Unit 2 Unit 2 LPCI and Containment Cooling Valve Checklist, Rev. 36
M-26, Low Pressure Coolant Injection (LPCI) System Diagram
DOP 0300-M1/E1, Unit 3 Control Rod Drive Hydraulic System Checklist, Rev. 32
DOP 0300-M4, Unit 3 Hydraulic Control Units East (Bank 3) Row 3 and 4, Rev. 03
DOP 0300-M2, Hydraulic Control Units West (Bank 1) Row 7 and 8, Rev. 03
M-365, Diagram of Control Rod Drive Hydraulic Piping
DOP 1400-M1/E1, Unit 3 Core Spray System, Revision 17
CR 214447; ASCO solenoid valves 2(3)-399-548A(B) and 548A(B); April 12, 2004
CR 231734; Unplanned LCO entry for CRD M-14 coupling check; June 25, 2004
CR 229869; Unplanned LCO entries for HCU K-6; June 19, 2004
DOP 1400-M1/E1; Unit 3 Core Spray System; Revision 17
M-358; Diagram of Core Spray Piping; Revision CC
1R05 Fire Protection
IR# 169275; 2/3 EDG interlock door malfunctioned; July 28, 2004
Dresden Unit 2 Fire Pre-Plan U2TB-43
Dresden Unit 2 Fire Pre-Plan U2TB-37
Dresden Unit 2 Fire Pre-Plan U2TB-36
Dresden Unit 3 Fire Pre-Plan U3TB-68
Dresden Unit 3 Fire Pre-Plan U3TB-69
OP-AA-201-001, Fire Marshall Tours, Revision 2
1R11 Operator Requalification
LT017, Simulator Exercise Guide, Revision 01, dated September 2004
CR 0255880; Target rock valve degradation found during valve rebuild,
September 22, 2004
1R06 Flood Protection
Document Based Instruction Guide; 12NL04; Operation of the Isocondenser External
Flood Emergency Make-up Pump; Revision 00
AR 111005; NRC Identifies Weakness in External Flood Procedure; June 5, 2002
Attachment
NRC Inspection Report 50-010/85013; 50-237/85030; 50-249/85026; dated
November 15, 1985
AD-AA-101; Floods; Revision 7
LS05-82-06-069; Safety Evaluation of Hydrology SEP Topics II-3.A; II-3.B; II-3.B.1;
and II-3.C; June 21, 1982
SA-1334; Input for NRC Contingent Dresden Phase 3 SDP Analysis - External Flooding
Frequency for Elevation 517'; Revision 0
CR 246038; DOA 0010-04 Flooding Procedure potentially inadequate; July 27, 2004
DOA 0010-04; Floods; Revision 16
DOA 0040-02; Localized Flooding in Plant; Revision 15
DOP 1300-03; Manual Operation of the Isolation Condenser; Revision 20
WO 668549; D2/3 QRT PM Emergency Diesel Pump (Flood pump) Operation;
July 9, 2004
CC-AA-309-1001; Capacity and Discharge Head for Portable Isolation Condenser
Make-up Pump to be used During Flood Conditions; Revision 0
UFSAR 2.4; Hydrologic Engineering; Revision 01A
UFSAR 3.4; Water Level (Flood) Design; Revision 4
1R13 Maintenance Risk Assessments and Emergent Work Control
Final Clear checklist # 30458
IR# 248839; B SBGT heater current relay out of tolerance; August 31, 2004
IR# 248991; Incorrect grid location for the 2/3-7506B in DOP 7500-M1/E1;
August 31, 2004
WO# 679078-01; Replace/regrease CR105X contacts; September 2, 2004
WO# 679077-01; Replace/regrease CR105X contacts; September 2, 2004
WO# 679080-01;Replace/regrease CR105X contacts; September 2, 2004
WO# 731568-03; Acoustic monitoring of piping to determine leaks outside, between
B CST and west side of trackway interlock, and 2/3 diesel generator room
OP-MW-109-101, Clearance Preparation and Approval Checklist, Rev. 2
WO# 724335; U3 250V Station Battery Cell #113
MA-DR-EM-6-83001; Battery Cell Jumpering, Rev. 0
EC 343009; Evaluation of Units 2&3 125V and 250V Battery Capacity with One (1) Cell
Jumpered as a 2003 Summer Contingency
EC 366236; Evaluation For Jumpering Of One Cell On The Unit 3 250VDC Safety
Related Battery
EC 350740; Evaluation Of Battery Cell Jumper Cart Molded Case Ckt Bkr (Unit 3)
250 Battery
CR 243971; NRC Identified Slight Corrosion On Two U3 125V Battery Posts;
August 12, 2004
1R12 Maintenance Effectiveness (71111.12)
CR 221610; Reactor Bldg dP low due to Degraded Purge Filter Housing; May 17, 2005
CR 219346; Following U3 scram, inadequate secondary containment dP; May 5, 2004
CR 208282; Loss of Rx Bldg DP during fan swap; March 14, 2004
CR 206777; Reactor building dP lost while stopping/starting RB Vent; March 7, 2004
7 Attachment
CR 197643; Reactor Building Differential Pressure >.25"; January 26, 2004
CR 173440; Rx bldg dP <.25" H2O due to starting unit 3 RB ventilation; August 28, 2003
1R15 Operability Evaluations
NED-I-EIC-0303; Reactor Water Level ATWS RPT/ARI Logic and ECCS Initiation
Setpoint Analysis and Reactor Pressure ATWS RPT/ARI Logic and Setpoint Analysis,
Rev. 5
DIS 0263-07, Unit 2 ATWS RPT/ARI and ECCS Level Transmitters Channel Calibration
Test and EQ Maintenance Inspection, Rev. 12
SIL No. 470S2; Non-Condensable Gas Buildup in RPV Water Level Instrumentation;
August 28, 1992
IR 245395; NRC Concern with Reactor Level Density Error; August 18, 2004
IR 245856; ERV discharge piping break flange does not meet USAS B31.1;
August 19, 2004
CR 229550; Unit 3 reactor Bldg Vent intake plenum collapsing; June 18, 2004
EC Eval 350806; U3 Reactor Building Ventilation Duct Collapsing
EC No. 334998; U3 Reactor Building Ventilation Duct Collapsing; June 27, 2004
CR 2411737; U3 RX Building HVAC duct work found collapsed in three areas;
August 4, 2004
CR 223169; U2 RX HVAC duct has split creating in-leakage path for SBGT;
May 24, 2004
OE 03-013, Electromatic Relief Valve Discharge Flanges, Revision 1
CR 204690: HPCI Steamline Water Carryover during Design Basis Events;
February 27, 2004
CR 194722; Previously Identified Problem Lead to a Smoked Component;
January 12, 2004
CR 208093; CR 105X Auxiliary Contactor Failure Analysis Results; March 12, 2004
CR 215956; Unit 3 Containment Cooling Service Water Keep Fill Line Does not Meet
Design Span Requirements; April 20, 2004
Control Room Logs August 23, and September 14, 2004
DOA 6500-12, Low Switchyard Voltage, Revisions 5 and 6
Technical Specifications 3.8.1, AC Sources -Operating
1R17 Permanent Plant Modification
EC 340303;Replacement of SBGT Solenoid Valves 2/3-7541-43A and B; Rev. 000
WO# 600451-01; Replace solenoid valve 2/3-7541-43B on AO-7510-B OPER;
September 14, 2004
MA-AA-726-620, Installation instructions for 0-600 Volt EQ Related Splices, Rev. 0
50.59 Screening Form
1R19 Post Maintenance Testing
WO# 99054268-01; D2/3 72M Eq Limitorque Vlv Oper Surv 2/3-7507-B
MA-AA-723-301, Periodic Inspection of Limitorque Model SMB/SB/SBD-000 Through
5 Motor Operated Valves, Rev. 1
WO# 565269-07; D3 2Y EQ GE 3B CS Pump Motor Surv
DOS 0040-32, LPCI and Core Spray Motor EQ Surveillance, Rev. 06
8 Attachment
DOS 1400-05; Core Spray System Pump Operability And Quarterly IST [Inservice Test]
Test With Torus Available
WO 344213-01; Disassemble & Inspect CS Min Flow Stop Check Valve
WO 724335-01; U3 250V Station Battery Cell #113, Revision 0 and Revision 1
MA-DR-EM-6-83001; Battery Cell Jumpering, Revision 0
WO# 00736967, Inspect/Repair Unit 2 HPCI Discharge Testable Check
Valve 2-2301-7"
DOS 7100-06, Seat Leakage Testing of Valve 2-2301-7," Revision 02
1R20 Refueling and Outage Activities
IR 240083; Outage vulnerability to crane issues; July 29, 2004
IR 240341; Supply identifies pre-outage milestone not met; July 29, 2004
IR 245395; NRC concern with reactor level density error; August 18, 2004
Operator Aid # 8, Rev. 0
DGP 01-01, Unit Startup, Revision 116
DGP 01-S1, Startup Checklist, Revision 63
DGP 01-S3, Unit 2 Mater Outage Checklist, Revision 18
DGP 02-01, Attachment B, Reactor Cooldown Monitoring, Revision 88
1R22 Surveillance Testing
WO# 9905344-01; D2/3 72M EG Limitorque Vlv Oper Surv 2/3 7504-B
MA-AA-723-301, Periodic Inspection of Limitorque Model SMB/SB/SBD-000 Through
5 Motor Operated Valves, Revision 1
Unit 2/3 DEP 40-09, Limitorque Valve Operator Maintenance, Revision 12
Exelon Procedure CC-MW-112-1001, Temporary Configuration Change Packages,
Revision 3
DAN 902(3)-4 G-13, Steam Dryer Parameter Alarmed, Revision 02
CR 254954; TCCP 347984, Steam Dryer Parameter Temporary Recorder; dated
September 20, 2004
2PS3 Radiological Environmental Monitoring and Radioactive Material Control Programs
Offsite Dose Calculation Manual; Chapters 5 - 6 and Appendices A - C (Revision 2),
Chapter 10 (Revision 4), Chapter 11 (Revision 2), Chapter 12 (Revision 5) and
Appendix F (Revision 2)
Environmental Inc. Midwest Laboratory, Sampling Procedures Manual; Revision 7
Dresden Nuclear Power Station Annual Radiological Environmental Operating Report
for 2002 (dated May 2003) and for 2003 (dated May 2004)
CY-AA-170-100; Radiological Environmental Monitoring Program; Revision 1
RP-AA-503; Unconditional Release Survey Method; Revision 0
TID-2004-003; Unconditional Release Detection Thresholds and Dose Consequences;
Revision 0
9 Attachment
Focus Area Self-Assessment Report; Radioactive Material Control and Radiological
Environmental Monitoring Program; dated June 14, 2004
Nuclear Oversight Health Physics/Radiation Protection Audit Report; Audit No. NOSA-
DRE-03-06; dated May 16, 2003
REMP, ODCM, Non-Radiological Effluent Monitoring Audit Report
Audit No. NOSA-DRE-03-08; dated November 19, 2003
Field Rotameter (serial numbers 95W012433 & 91W506166) Quarterly Flow
Verifications for January 2003 - July 2004
Field Rotameter (serial numbers 95W012433 & 91W506166) Calibration Certificates;
dated May 6, 2003 and July 17, 2003, respectively
Master Rotameter (serial number 91W513308) Calibration Certificate; dated August 12,
2002 and August 8, 2003
Annual Maintenance and Monthly Flow Checks for Environmental Air Sample
Pumps; Pump #s 445,455,486,457,454,458,446,443,452,431,453,451,429 and 462;
January 2003 - June 2004
Murray and Trettel, Inc. Monthly Reports on the Meteorological Monitoring Program at
the Dresden Station; January 2003 - May 2004
CR 00147626; Magenta Tools Found Outside RCA; dated March 5, 2003
CR 00116137; High Tritium Concentration in Non-REMP Well; dated July 18, 2002 and
Associated Apparent Cause Evaluation; dated January 21, 2003
CR 00157499; Excessive Off-Site Sampler Shutdowns for 2002; dated May 6, 2003
CR 00181131; Yellow Velcro Strap Found in Venture Break Area; dated
October 14, 2003
CR 00181367; Infra-Red Camera Released While Isotopic Showed Cobalt and
Manganese; dated October 16, 2003
CR 00181692; Individual Alarms Portal Monitor at Braidwood Station; dated
October 16, 2003
CR 00183938; PM-7 Gatehouse Alarm - Found Particle on Boot Lace; dated
October 30, 2003
CR 00184544; Low-Level Radioactive Clothing Found Outside the RCA; dated
November 2, 2003
4OA1 Performance Indicator Verification
LS-AA-2150; Attachment 1; Monthly PI Data Elements for RETS/ODCM Radiological
Effluent Occurrences; April 2003 - June 2004
Quarterly Summary Data of Dresden Station Units 2/3 Maximum Doses Resulting from
Airborne Releases and from Aquatic Effluents; 2nd Quarter 2003 - 2nd Quarter 2004
4OA3 Event Follow-up
Operability Evaluation No.04-008, Main Condenser Hood/Bay, Revision 0
Operability Evaluation No.04-008, Unit 2 & 3 2A and 3C Condenser Bay Vacuum
Indication/Switch Sometimes Indicates a Non-conservative Value after a Flow Reversal
to East-to-West Flow, Revision 1
CR 218325; Condenser Vacuum Indication Error Caused by Condensation; May 1, 2004
CR 221099; Bad vacuum indication taken from the 3C main condenser hood was
previously reported in CR 218325;
10 Attachment
CR 213244; Apparent Error in Condenser Turbine Hood Vacuum Indication;
April 5, 2004
CR 234361; NRC Questions Potentially Exceeding Tech Spec Comp Time; July 1, 2004
DOA 200-01, Recirculation (Recirc) Pump Trip - One or Both Pumps, Revision 25
DOS 0500-18, Verification of Flow Control Line and Average Core Thermal Power,
Revision 27
NES-EIC-40.01, Large Motor (>2kV) Repair Requirements, Revision 1
CR 217533; Unit 2 TADS trigger manually disabled; April 28, 2004
CR 217570; Unit 2 scram due to 2A Recirc pump trip; April 28, 2004
LER 50-237/249/2004-003-00, Unit 3 Scram Due to Loss of Offsite Power and
Subsequent Inoperability of the Standby Gas Treatment System for Units 2 and 3,
dated July 6, 2004
CR 219063; Switching Fault Causes LOOP and Reactor Scram; May 5, 2004
WO 0069088-01, Rebuild Operating Mechanism All Phases BT 6-7 CB
Exelon Energy Delivery Maintenance Template, Circuit Breaker 2 Pressure SF6, 2004
Revision 2
CR 219062, Unit 3 Startup Aborted due to Insufficient SRMs, dated 05/08/2004
Technical Specification 3.3.1.2, SRM Instrumentation
Control Room Logs May 8, 2004
11 Attachment