ML040160461
| ML040160461 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 01/16/2004 |
| From: | Fredrickson P NRC/RGN-II/DRP/RPB4 |
| To: | Gannon C Carolina Power & Light Co |
| References | |
| IR-03-006 | |
| Download: ML040160461 (38) | |
See also: IR 05000324/2003006
Text
January, 16, 2004
Carolina Power and Light Company
ATTN: Mr. C. J. Gannon
Vice President
Brunswick Steam Electric Plant
P. O. Box 10429
Southport, NC 28461-0429
SUBJECT:
BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION
REPORT NOS. 05000325/2003006 AND 05000324/2003006
Dear Mr. Gannon:
On December 20, 2003, the Nuclear Regulatory Commission (NRC) completed an inspection at
your Brunswick Units 1 and 2 facilities. The enclosed integrated inspection report documents
the inspection findings, which were discussed on December 18, 2003, with you and other
members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
This report documents one finding concerning an inadequate design review of a Unit 2 reactor
feed pump speed control system modification. This finding has potential safety significance
greater than very low significance. This finding did present an immediate safety concern.
However, compensatory measures are in place while long-term corrective measures are being
implemented. In addition, the report documents one self-revealing finding of very low safety
significance (Green). This finding was determined to involve a violation of NRC requirements.
However, because of the very low safety significance and because it is entered into your
corrective action program, the NRC is treating this finding as a non-cited violation (NCV)
consistent with Section VI.A of the NRC Enforcement Policy. Additionally, a licensee-identified
violation which was determined to be of very low safety significance is listed in this report. If
you contest any non-cited violation in this report, you should provide a response within 30 days
of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the
Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the
Brunswick Steam Electric Plant.
2
In accordance with 10CFR 2.790 of the NRCs 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 NRCs 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/
Paul E. Fredrickson, Chief
Reactor Projects Branch 4
Division of Reactor Projects
Docket Nos.: 50-325, 50-324
Enclosure:
Inspection Report 05000325, 324/2003006
w/Attachment: Supplemental Information
cc w/encl:
(See page 3)
3
cc w/encl:
W. C. Noll, Director
Site Operations
Brunswick Steam Electric Plant
Carolina Power & Light
Electronic Mail Distribution
David H. Hinds
Plant Manager
Brunswick Steam Electric Plant
Carolina Power & Light Company
Electronic Mail Distribution
James W. Holt, Manager
Performance Evaluation and
Regulatory Affairs PEB 7
Carolina Power & Light Company
Electronic Mail Distribution
Edward T. ONeil, Manager
Support Services
Carolina Power & Light Company
Brunswick Steam Electric Plant
Electronic Mail Distribution
Lenny Beller, Supervisor
Licensing/Regulatory Programs
Carolina Power and Light Company
Electronic Mail Distribution
William D. Johnson
Vice President & Corporate Secretary
Carolina Power and Light Company
Electronic Mail Distribution
John H. ONeill, Jr.
Shaw, Pittman, Potts & Trowbridge
2300 N. Street, NW
Washington, DC 20037-1128
Beverly Hall, Acting Director
Division of Radiation Protection
N. C. Department of Environment
and Natural Resources
Electronic Mail Distribution
Peggy Force
Assistant Attorney General
State of North Carolina
Electronic Mail Distribution
Chairman of the North Carolina
Utilities Commission
c/o Sam Watson, Staff Attorney
Electronic Mail Distribution
Robert P. Gruber
Executive Director
Public Staff NCUC
4326 Mail Service Center
Raleigh, NC 27699-4326
Public Service Commission
State of South Carolina
P. O. Box 11649
Columbia, SC 29211
Donald E. Warren
Brunswick County Board of
Commissioners
P. O. Box 249
Bolivia, NC 28422
Warren Lee
Emergency Management Director
New Hanover County Department of
Emergency Management
P. O. Box 1525
Wilmington, NC 28402-1525
Distribution w/encl: (See page 4)
4
Distribution w/encl:
B. Mozafari, NRR
L. Slack, RII EICS
RIDSRIDSNRRDIPMLIPB
PUBLIC
OFFICE
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SIGNATURE
GTM
JDA
MAS1
JLK1
KFO
EXL2
NAME
GMacdonald:as
EDiPaolo
JAustin
MScott
JKreh
KODonohue
ELea
DATE
01/15/04
01/16/04
01/16/04
01/15/04
01/15/04
01/15/04
01/15/04
E-MAIL COPY?
YES
NO YES
NO YES
NO YES
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PUBLIC DOCUMENT
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OFFICIAL RECORD COPY DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML040160461.wpd
Enclosure
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-325, 50-324
License Nos:
Report Nos:
05000325/2003006 and 05000324/2003006
Licensee:
Carolina Power and Light (CP&L)
Facility:
Brunswick Steam Electric Plant, Units 1 & 2
Location:
8470 River Road SE
Southport, NC 28461
Dates:
September 21, 2003 - December 20, 2003
Inspectors:
E. DiPaolo, Senior Resident Inspector
J. Austin, Resident Inspector
G. MacDonald, Senior Project Engineer (Section 1R06)
M. Scott, Senior Reactor Inspector (Section 1R12)
J. Kreh, Emergency Preparedness Inspector (Section 1EP 2-5)
K. ODonohue, Senior Reactor Inspector (Section 1R11)
E. Lea, Senior Operations Engineer (Section 1R11)
Approved by:
Paul Fredrickson, Chief,
Reactor Projects Branch 4
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000325/2003-006, 05000324/2003-006; 09/21/2003-12/20/2003; Brunswick Steam
Electric Plant, Units 1 and 2; Maintenance Effectiveness, Permanent Plant Modifications.
The report covered a three-month period of inspection by resident inspectors, a senior project
engineer, a senior operations engineer, senior reactor inspectors, and a regional emergency
preparedness inspector. One Green non-cited violation (NCV) was identified. The significance
of most findings is indicated by its color (Green, White, Yellow, Red) using Inspection Manual
Chapter (IMC) 609, Significance Determination Process (SDP). Findings for which the SDP
does not apply may be Green or be assigned a severity level after NRC management review.
The NRC's program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
A.
NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
Green. A self-revealing non-cited violation was identified for the licensees
failure to position the Unit 2 high pressure coolant injection (HPCI) system
turbine exhaust stop check valve in the open position following system
maintenance, in accordance with plant procedures. This resulted in failure of
the exhaust line rupture discs during testing, a primary containment isolation
of the system, and activation of the HPCI room fire protection system.
This finding is greater than minor because it is associated with system
configuration control and affected the mitigating availability of the HPCI system.
This finding was determined to be of very low safety significance (Green)
because the HPCI system was returned to an operable status within the
Technical Specification allowed outage time. The finding was related to the
cross-cutting aspect of Human Performance because the cause was determined
to be due to plant operators using improper techniques in verifying the valves
position. Other contributing causes including operator knowledge deficiencies of
valve operation, failure to perform an independent check of valve position, and
the pre-job briefs limited scope were also related to Human Performance.
(Section 1R12)
Cornerstone: Initiating Events and Mitigating Systems
To Be Determined (TBD). A self-revealing finding was identified for an
inadequate design review of a Unit 2 reactor feed pump speed control
modification. The modification replaced the existing mechanical-hydraulic speed
control system with a digital speed control system. The system is powered by
internal power supplies that would fault, and thus cease to supply output power,
with one cycle of sensed abnormal supply voltage. As a result, the reactor feed
pumps would trip following a unit trip due to the supply voltage transient caused
by the swap of in-house loads from the unit auxiliary transformer to the startup
auxiliary transformer.
2
Enclosure
The finding is unresolved pending completion of a significance determination.
This issue is greater than minor because, if left uncorrected, it would increase
the likelihood of initiating events caused by a loss of reactor feed pumps
following transients and affect the reliability and functional capability of the
reactor feed pumps to mitigate events (unit trips). The finding was determined to
have potential safety significance greater than very low because of the increased
likelihood of initiating events, resultant reduced functional capability of the
reactor feed pumps to mitigate events as a result, and the length of time the
condition existed. (Section 1R17)
B.
Licensee Identified Violations
A violation of very low safety significance, was identified by the licensee and 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
action are listed in Section 4OA7 of this report.
Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 began the report period operating at full power. On September 27, 2003, power was
reduced to approximately 50 percent to perform planned maintenance on the reactor feed
pumps and testing on the control rods and main steam isolation valves. The unit returned to
maximum power on September 29. On November 14, power was reduced to approximately 50
percent for planned maintenance, control rod scram solenoid pilot valve maintenance, and
surveillance testing. The unit returned to maximum power on November 16. Power was
reduced to approximately 50 percent on November 21 to troubleshoot speed control problems
on the A reactor feed pump. Full power was achieved on November 23 where it remained for
the duration of the inspection period.
Unit 2 began the report period operating at full power. On September 23, 2003, power was
reduced to approximately 50 percent to facilitate repairs to a main condenser tube leak. The
unit returned to full power on September 25. On November 4, Unit 2 tripped due to a loss of
main generator field. The loss of field was caused by the failure of the main generator
alternator brush/collector ring (see Section 4OA3 for additional details). Following repairs to the
main generator exciter, a unit startup was commenced on November 7, and maximum power
was achieved on November 9. On December 5, the unit reduced power to approximately 50
percent to facilitate a modification to the reactor feed pumps to supply the governors with an
uninterruptible power source (see Section 1R17 for details). The unit returned to maximum
power on December 8 where it remained for the duration of the inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01
Adverse Weather Protection
a. Inspection Scope
The inspectors assessed the effectiveness of the licensees cold weather protection
program as it related to ensuring that the facilitys diesel-driven fire pump, emergency
diesel generators, and condensate storage tank low level switches would remain
functional and available in cold weather conditions. In addition to reviewing the
licensees program-related documents and procedures, walkdowns were conducted of
the freeze protection equipment (e.g., heat tracing, area space heaters, etc.) associated
with the above systems/components. Licensee problem identification and resolution
was also assessed. This included review of Action Request (AR) 110949 which
documented that freeze protection preventive maintenance was not completed as
scheduled for Unit 2. Documents reviewed during the course of this inspection are
listed in the Attachment.
b. Findings
No findings of significance were identified.
2
Enclosure
1R04
Equipment Alignment
a. Inspection Scope
Partial System Walkdowns
The inspectors performed three partial walkdowns of the below listed systems to verify
that the systems were correctly aligned while the redundant train or system was
inoperable or out-of-service (OOS) or, for single train risk significant systems, while the
system was available in a standby condition. The inspectors assessed conditions such
as equipment alignment (i.e., valve positions, damper positions, and breaker alignment)
and system operational readiness (i.e., control power and permissive status) that could
affect operability. The inspectors reviewed the resolution of licensee identified
equipment alignment problems that could cause initiating events or impact mitigating
system availability. The inspectors reviewed available structures, systems or
components (SSCs) to verify that they met the requirements of the licensees
configuration control program. The inspectors reviewed documents listed in the
Attachment.
Unit 1 conventional and B train nuclear service water pumps when A train
nuclear service water pump was OOS for planned maintenance on October 1,
2003.
Unit 2 HPCI system when reactor core isolation cooling (RCIC) system was OOS
for planned maintenance on October 23, 2003.
Unit 2 RCIC system when HPCI system was inoperable due to ruptured exhaust
diaphragms on November 13-14, 2003.
Complete System Walkdown
The inspectors conducted a detailed review of the alignment and condition of the
emergency diesel generators (EDGs). The inspector reviewed the Updated Final Safety
Analysis Report, associated attachments of Diesel Generator Operating Procedure
0OP-39, and the system flow diagram (drawing numbers D-02265 through D-02274).
The inspectors reviewed pending design and equipment issues to verify that the
identified deficiencies did not significantly impact the systems functions. Items included
in this review were: 1) the operator workaround list; 2) the temporary modification list; 3)
outstanding maintenance work requests/work orders (WOs); and 4) operator turnover
sheets. The following related ARs were reviewed to assure that the licensee had
properly characterized and prioritized equipment problems in the corrective action
program:
AR 49367
EDG 2 Inoperable due to high cylinder exhaust temperature
AR 55517
EDG 4 light socket short
AR 86529
Unexpected diesel generator start during SCRAM on January 1,
2003
AR 102323102323480V maintenance rule functional failure - feeder breaker to motor
control center DGC (2-E7-AY8-52) failed to trip
3
Enclosure
b. Findings
No findings of significance were identified.
1R05
Fire Protection
a. Inspection Scope
The inspectors reviewed current ARs and WOs associated with the fire suppression
system to confirm that their disposition was in accordance with OAP-033, Fire Protection
Program Manual. The inspectors reviewed the status of ongoing surveillance activities
to verify that they were current to support the operability of the fire protection system. In
addition, the inspectors observed the fire suppression and detection equipment to
determine whether any conditions or deficiencies existed which would impair the
operability of that equipment. The inspectors toured the following areas important to
reactor safety and reviewed documents listed in the Attachment to verify that the
requirements for fire protection design features, fire area boundaries, and combustible
loading were met:
Units 1 and 2 north and south emergency core cooling pipe tunnels (4 areas)
EDG fuel cells, -1 foot 6 inch elevation (1 area)
EDG basement, 2 foot elevation (1 area)
b. Findings
No findings of significance were identified.
1R06
Flood Protection Measures
a. Inspection Scope
The inspectors reviewed the licensees internal flooding analysis as described in
Updated Final Safety Analysis Report (UFSAR) Section 3.4.2, Protection From Internal
Flooding. Due to the risk significance of equipment in the diesel generator building and
the reactor buildings, the inspectors reviewed UFSAR Section 3.4.2 analysis of the
effects of postulated piping failures for these two areas to determine if the analysis
assumptions and conclusions were based on the current plant configuration. The
internal flooding design features and equipment for coping with internal flooding was
inspected. The walkdown included sources of flooding and drainage, sump pumps,
level switches, watertight doors, curbs , pedestals and equipment mounting. The
inspectors reviewed the testing of the level alarms and reviewed the procedures for
coping with internal flooding. Documents reviewed are listed in the Attachment.
4
Enclosure
External Flooding
The inspectors reviewed the licensees external flooding analysis as described in
UFSAR Section 3.4.1, Protection from External Flooding, to determine the external flood
control design features. Walkdowns were conducted to inspect the external flood
protection barriers including watertight doors, curbs, sealing of external building
penetrations below floodline, and the sump pumps and level alarm circuits. Procedures
for coping with external flooding were reviewed and the inspectors walked down the
portable flood protection equipment listed in Procedure 0AI-68, Brunswick Nuclear Plant
Response to Severe Weather Warnings. Documents reviewed are listed in the
Attachment.
b. Findings
No findings of significance were identified.
1R07
Heat Sink Performance
a. Inspection Scope
The inspectors reviewed activities associated with the cleaning of the EDG 4
turbocharger intercooler heat exchange per WO 453062. The inspectors reviewed the
results of the EDG 4 intercooler inspection conducted in accordance with preventive
maintenance procedures. The inspection results were analyzed to determine if
inspection frequencies were adequate to detect degradation prior to loss of heat
removal capability below design-basis values. The inspectors reviewed the documents
listed in the Attachment.
b. Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification
a. Inspection Scope
Quarterly Review
On November 4, 2003, the inspectors observed licensed operator performance and
reviewed the associated training documents during two simulator examinations. The
simulator observations and reviews included evaluations of emergency operating
procedure and abnormal operating procedure utilization. The inspectors reviewed
LORX-001 and LORX-035 which documented the associated simulator examination
scenarios. The simulator examination evaluated operator response to plant transients
initiated by plant equipment problems, reactivity manipulations, a small break loss of
coolant accident with failures of emergency core cooling systems, and an unisolable
steam leak outside containment. The inspectors reviewed operator activities to verify
5
Enclosure
consistent clarity and formality of communication, conservative decision-making by the
crew, appropriate use of procedures, and proper alarm response. Group dynamics and
supervisory oversight, including the ability to properly identify and implement appropriate
Technical Specification (TS) actions, regulatory reports, and notifications, were
observed. The inspectors assessed whether appropriate feedback was planned to be
provided to the licensed operators. The inspectors reviewed documents listed in the
Attachment.
Periodic Evaluation (Biennial)
The inspectors reviewed documentation, interviewed licensee personnel, and observed
the administration of simulator operating tests associated with the licensees operator
requalification program. Job performance measures (JPMs) associated with the
licensees operator requalification program, which the licensee administered at the
beginning of the year, were reviewed by the inspectors. Each of the activities performed
by the inspectors was done to assess the effectiveness of the licensee in implementing
requalification requirements identified in 10 CFR 55, Operators Licenses. Evaluations
were also performed to determine if the licensee effectively implemented operator
requalification guidelines established in NUREG-1021, Operator Licensing Examination
Standards for Power Reactors. The inspectors also reviewed and evaluated the
adequacy of the licensees simulation facility for use in operator licensing examinations.
The inspectors observed three crews during the performance of the operating tests.
Documentation reviewed included written examinations, JPMs, simulator scenarios,
licensee procedures, on-shift records, licensed operator qualification records,
watchstanding and medical records, simulator modification request records and
performance test records, the feedback process, and remediation plans. Documents
reviewed during the inspection are listed in the Attachment.
Following the completion of the annual operating examination testing cycle which ended
on December 9, 2003, the inspectors reviewed the overall pass/fail results of the
individual JPM operating tests, and the simulator operating tests administered by the
licensee during the operator licensing requalification cycle. These results were
compared to the thresholds established in NRC Inspection Manual Chapter 0609
Appendix IProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609</br></br>Appendix I" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., Operator Requalification Human Performance Significance Determination
Process.
b. Findings
No findings of significance were identified.
6
Enclosure
1R12
Maintenance Effectiveness
a. Inspection Scope
Periodic Evaluation (Biennial)
The inspectors reviewed the licensees Maintenance Rule periodic assessment, "BNP
Maintenance Rule Program Periodic Self-Assessment Plan," for June 1, 2001 to May
31, 2003, dates of assessment July 21-24, 2003, while on-site the week of September
14, 2003. The report was issued to satisfy paragraph (a)(3) of 10 CFR 50.65, and
covered the period as indicated for two units. The inspection was to determine the
effectiveness of the assessment and that it was issued in accordance with the time
requirement of the Maintenance Rule (MR) and included evaluation of: balancing
reliability and unavailability, (a)(1) activities, (a)(2) activities, and use of industry
operating experience. To verify compliance with 10 CFR 50.65, the inspectors reviewed
selected MR activities covered by the assessment period for the following MR systems:
containment isolation valves, radiation monitors, main steam isolation valves, instrument
air system, and isolated-phase bus duct. Specific procedures and documents reviewed
are listed in the Attachment.
During the inspection, the inspectors reviewed selected plant WO data, the site
guidance implementing procedure, discussed and reviewed relevant corrective action
issues (ARs/CRs), reviewed generic operations event data, probabilistic risk data, and
discussed issues with system engineers. Operational event information was evaluated
by the inspectors in its use in MR functions. The inspectors selected WOs, and MR
assessments, and other corrective action documents of systems recently removed from
10 CFR 50.65 a(1) status and those in a(2) status for some period to assess the
justification for their status. The documents were compared to the sites MR program
criteria, and the MR a(1) evaluations and rule related data bases.
Routine Maintenance
For the equipment issues described in work documents listed below, the inspectors
reviewed the licensees implementation of the Maintenance Rule (10 CFR 50.65) with
respect to the characterization of failures, the appropriateness of the associated
Maintenance Rule a(1) or a(2) classification, and the appropriateness of the associated
a(1) goals and corrective actions. The inspectors evaluated licensee work controls or
practices to assess whether these activities contributed to the degraded performance or
condition. The inspectors also reviewed operations logs and licensee event reports to
verify unavailability times of components and systems, if applicable. Licensee
performance was evaluated against the requirements of Procedure ADM-NGG-0101,
Maintenance Rule Program. The inspectors also reviewed deficiencies related to the
work activities listed below to verify that the licensee had identified and resolved
deficiencies in accordance with Procedure CAP-NGGC-0200, Corrective Action.
7
Enclosure
AR 110705110705Actuation of the Unit 2 high pressure coolant injection system
steam exhaust rupture discs during the performance of testing
following a system maintenance outage
AR 110948110948Radioactive waste effluent radiation monitor alarmed and
automatically secured detergent drain tank discharge
b. Findings
Introduction. A Green NCV was identified for failure to position a Unit 2 HPCI system
valve as required by a clearance order following maintenance activities.
Description. During the performance of Unit 2 HPCI system testing following
maintenance activities on November 12, 2003, the HPCI system automatically isolated
on a primary containment Group 4 isolation signal as a result of high pressure as
measured between the two (series mounted) turbine exhaust line rupture discs. High
turbine exhaust pressure resulted in a HPCI turbine trip, exhaust rupture disc failures,
and the actuation of the HPCI room carbon dioxide system due to the resultant room
high temperatures. The licensee found that the high turbine exhaust pressure was
caused by the turbine exhaust line to suppression pool stop check valve (2-E42-F021)
improperly being left in the closed position following the completion of maintenance
activities earlier that day. Following damage assessment and repairs caused by the
event, the HPCI system was declared operable on November 16, 2003.
The licensee determined the root cause to be the failure of auxiliary operators
performing the restoration lineup to properly check that valve 2-E41-F021 was in the
open position in accordance with plant practices. They failed to position the valve in the
open position in accordance with system restoration Clearance Order 60551.
Administrative Procedure 0AO-013, Plant Equipment Control, Revision 9, directs
operators to first stroke a valve in the close direction, and then return the valve to the
fully open position, when checking valves in the open position. Valve 2-E41-F021 has an
impacting type handwheel which allows the valve to be positioned with the aid of valve
handwheel inertia. The auxiliary operators were unfamiliar with this valve operational
feature and, as a result, were unsuccessful in moving the valve stem when they
attempted to turn the handwheel without the aid of impact. The operators deduced that
the valve was already in the open position based on the inability to turn the valve in the
open direction and the appearance that the valve was open based on valve stem
position.
In addition, the licensees investigation revealed other human performance-based
problems including: 1) one auxiliary operator performing the check did not attend the
prejob brief; 2) the prejob brief was limited in scope leaving the attending auxiliary
operator uncertain of valve locations, which contributed the position check being
performed concurrently; and 3) the auxiliary operators did not consult supervision when
they performed the check concurrently, versus independently, which was also not in
accordance with licensee expectations. The licensee planned corrective actions to
address the identified issues.
8
Enclosure
Analysis. The failure to position HPCI system valve 2-E41-F021 in accordance with
Clearance Order 60551 following maintenance activities is greater than minor because it
is associated with system configuration control and affected the mitigating availability of
the HPCI system. This finding was determined to be of very low safety significance
(Green) because the HPCI system was returned to an operable status within the TS
allowed outage time. The finding was related to the cross-cutting aspect of Human
Performance because the cause was determined to be due to plant operators using
improper techniques in verifying the valves position. Other contributing causes
including operator knowledge deficiencies of valve operation, failure to perform an
independent check of valve position, and the pre-job briefs limited scope were also
related to Human Performance.
Enforcement. Technical Specification 5.4.1.a. requires that written procedures shall be
implemented covering applicable procedures recommended in Regulatory Guide 1.33,
Appendix A, November 1972. Regulatory Guide 1.33 requires written procedures for
equipment control (e.g., locking and tagging). Equipment control Clearance Order
60551 required HPCI system valve 2-E41-F021 (turbine exhaust line to suppression
pool stop check valve), to be in the open position following maintenance activities on the
HPCI system on November 12, 2003. Contrary to Clearance Order 60551, valve 2-E41-
F021 was left in the closed position following the completion of maintenance activities on
November 12, 2003. Because this failure to follow Clearance Order 60551 is of very low
safety significance and has been entered into the licensees corrective action program
(AR 110705110705, this violation is being treated as an NCV, consistent with Section VI.A of
the NRC Enforcement Policy: NCV 05000324/2003006-01, Failure to Position HPCI
System Valve in Accordance with Clearance Order.
1R13
Maintenance Risk Assessments and Emergent Work Evaluation
a. Inspection Scope
The inspectors reviewed the licensees implementation of 10 CFR 50.65 (a)(4)
requirements during scheduled and emergent maintenance activities. The inspectors
reviewed the effectiveness of risk assessments performed prior to changes in plant
configuration for maintenance activities (planned and emergent). The review was
conducted to verify that, upon unforseen situations, the licensee had taken the
necessary steps to plan and control the resultant emergent work activities. The
inspectors reviewed the applicable plant risk profiles, work week schedules, and
maintenance WOs for the following OOS equipment or conditions, and the documents
listed in the Attachment:
Service water intake structure bay cleaning
AR 108100108100EDG 4 inoperable due to failed low lubricating oil pressure switch
relay (2-DG4-LPSCR)
Vital battery 1B-1 declared inoperable due to low voltage on cell
- 10 during Work Week 41
AR 110705110705Unit 2 HPCI system steam exhaust rupture disc failure and
restoration to operable status
9
Enclosure
AR 110399110399Elevated integrated core damage probability on Unit 2 due to
reactor feed pump speed control system power supply sensitivity
to voltage fluctuations
AR 105246105246Unit 2 power reduction to repair main condenser tube leak
Repair motor-driven fire pump breaker compartment
To assess the licensees identification and resolution of problems, the inspectors
reviewed AR 112681112681associated with inconsistent risk evaluations for EDG wipedowns,
and AR 112544112544which documented issues associated with risk reduction compensatory
actions during the implementation of modifications on the Unit 2 reactor feed pump
speed control system.
b. Findings
No findings of significance were identified.
1R14
Operator Performance During Non-Routine Plant Evolutions and Events
a. Inspection Scope
The inspectors reviewed or observed the operating crews performance during the
following unplanned transient/abnormal conditions to verify the response to the event
was in accordance with procedures and training. Operator logs, plant computer data,
and associated operator actions were reviewed as well as the procedures listed in the
Attachment.
Operating crew performance and reactivity management during portions of the
Unit 2 down power and power escalation to repair a main condenser tube leak
occurring September 23-25, 2004.
Unit 2 reactor scram due to failure of the main generator exciter occurring on
November 4, 2003. Plant response to the failure resulted in the load shedding of
various plant loads, the tripping of the reactor feed pumps, and the loss of the
normal decay heat removal heat sink (main condenser) due to the receipt of a
primary containment isolation of Group 1 (i.e., main steam line isolation).
Operating crew performance and reactivity management during portions of the
Unit 2 control rod pull to criticality following repairs to the main generator exciter
on November 7, 2003.
Unit 2 HPCI system primary containment isolation and fire protection system
activation occurring on November 12, 2003. The transient resulted in challenges
to operators including unexpected isolation indications. Additionally, adverse
atmospheric conditions in the reactor building required deferral of fire protection
compensatory measures.
10
Enclosure
b. Findings
No findings of significance were identified.
1R15
Operability Evaluations
a. Inspection Scope
The inspectors reviewed the operability evaluations associated with the following six
issues, which affected risk significant systems or components, to assess as appropriate:
1) the technical adequacy of the evaluations; 2) the justification of continued system
operability; 3) any existing degraded conditions used as compensatory measures; 4) the
adequacy of any compensatory measures in place, including their intended use and
control; and 5) where continued operability was considered unjustified, the impact on TS
limiting conditions for operations (LCOs) and the risk significance. In addition to the
reviews, discussions were conducted with the applicable system engineer regarding the
ability of the system to perform its intended safety function. The inspectors reviewed the
documents listed in the Attachment.
AR 70787
Unit 2 residual heat removal system loop B pressurization due to
leakage past inboard low pressure coolant injection isolation valve
(2-E11-F015B)
AR 109435109435Vital battery 1A-2, cracked positive plate discovered cell #50
AR 110037110037Unit 2 standby gas treatment train A failure to start as required
following the Unit 2 reactor scram occurring on November 4, 2003
AR 105510105510Foreign material found in EDG 4 inter-cooler end cap
AR 111812111812Unit 2 residual heat removal system pipe support (2-E11-34FH88)
broken
AR 110948110948Radioactive waste radiation monitor Hi-Hi alarm received while
discharging the detergent drain tank
To assess the licensees identification and resolution of problems, the inspectors
reviewed AR 109291109291 associated with the loss of standby liquid control loop B squib
valve continuity on Unit 2, while working in the A loop circuit.
b. Findings
No findings of significance were identified.
11
Enclosure
1R16
Operator Work-Arounds (OWAs)
a. Inspection Scope
Selected OWAs
The inspectors reviewed the status of OWAs for Units 1 and 2 to verify that the
functional capability of the system or operator reliability in responding to an initiating
event was not affected. The review was to evaluate the effect of the OWA on the
operators ability to implement abnormal or emergency operating procedures during
transient or event conditions. The inspectors compared licensee actions to the
requirements of Procedure 0OI-01.08, Control of Equipment and System Status and
held discussions with operations personnel related to the OWAs reviewed.
The OWAs reviewed were:
1093
Interlock between reactor building doors 402 and 403 is broken
1028
Low pressure core injection line is pressurizing due to reactor coolant
inleakage
Cumulative Effects Review
The inspectors reviewed the cumulative effects of all identified operator work-arounds
and their: 1) impact on the reliability, availability, and potential for misoperation of the
effected systems; 2) potential for increasing an initiating event frequency; and 3) impact
on the ability of operators to respond in a correct and timely manner to a plant transient
and accident. Aggregate impacts of the identified work-arounds on each individual
operator watch station were also reviewed.
The inspectors held discussions with the OWA coordinator and reviewed the OWA
database to determine their cumulative effects. The effect of the work-arounds on
reliability, availability, and potential misoperations of the systems involved were
reviewed. The inspectors reviewed the OWAs on Unit 1 and Unit 2 to verify that no
increase in initiating event frequency occurred and that the OWA could not affect
multiple mitigating systems. The cumulative effects of OWAs on operators correct and
timely response to plant transients and accidents were also reviewed by the inspectors.
b. Findings
No findings of significance were identified.
12
Enclosure
1R17
Permanent Plant Modifications
a. Inspection Scope
The inspectors reviewed a permanent plant modification documented in Engineering
Change (EC) 46822 that modified the Unit 2 reactor feed pump speed control system
with a digital speed control system. One purpose of the review was to verify that the
modification met the design bases and the design assumptions. Another purpose was
to verify that modification implementation did not impair emergency/abnormal operating
procedure actions and key safety functions. The inspectors also reviewed the
modification to verify that unintended system interactions would not occur, and that no
additional failure modes were introduced.
b. Findings
Introduction. An unresolved item (URI) was identified for an inadequate design review
of a modification implemented on the Unit 2 reactor feed pump speed control system.
This is a URI pending completion of the SDP.
Description. During the Spring 2003 Unit 2 outage, the licensee implemented a
modification to the reactor feed pump speed control system. This modification, EC 46822, replaced the existing mechanical-hydraulic speed control system with a digital
speed control system (Woodward TMR 5009). During investigation as to the cause of
the reactor feed pumps tripping during the November 4, 2003 reactor trip, (See Section
40A3.2) the licensee determined that a trip of both reactor feed pumps would occur
following Unit 2 turbine trips. The licensee found that the digital speed control system
power supplies (two auctioneered for each reactor feed pump) were designed to sense
a fault condition within one cycle of abnormal supply voltages. The power supplies
would fault, and thus cease to supply output power, if incoming voltage was sensed
greater than 132 volts (AC) or less than 88 volts (AC). Simultaneous faults in the power
supplies would result in the reactor feed pump tripping.
The speed control system power supplies ultimately receive power from the 2C and 2D
Buses. These buses are provided with an automatically initiated, automatically
executed, quick, dead bus transfer. The scheme is capable of quickly transferring each
bus section and its loads from the normal source (Unit Auxiliary Transformer) to the
preferred source (Startup Auxiliary Transformer) in the event of a loss of the normal
power source or unit/turbine trip. This transfer results in the buses being disconnected
from both voltage sources for a period of between one and five cycles, per the UFSAR.
The licensee concluded that there was a high probability that reactor feed pump speed
control power supplies would fault during the period that the 2C and 2D are
disconnected from both voltage sources due to the sensitivity of the power supplies to
detect abnormally low voltage (i.e., less than 88 volts for 1 cycle). As a result, the
reactor feed pumps would trip following unit/turbine trips and during certain voltage
transients on the 2C and 2D Buses. The licensees evaluation of the modification failed
to recognize this vulnerability.
13
Enclosure
The licensee implemented compensatory work risk measures because of the resultant
elevated integrated core damage probability introduced by the reactor feed pump speed
control system vulnerabilities. The licensee promptly initiated corrective actions (AR
110399) and developed a modification to supply the reactor feed pump control system
with an uninterruptible power source.
On December 7, 2003, the licensee completed the modifications to the reactor feed
pump speed control system, which eliminated the vulnerabilities introduced by EC 46822. The licensee also plans to include uninterruptible power sources to the reactor
feed pump governors planned to be modified on Unit 1 in the Spring 2004 refueling
outage.
Analysis. The inadequate design review of the Unit 2 reactor feed pump speed control
system modification (EC 46822) affects the Initiating Events and Mitigating System
cornerstones. This issue is greater than minor because if left uncorrected, it would
increase the likelihood of initiating events caused by a loss of reactor feed pumps
following transients and affect the reliability and functional capability of the reactor feed
pumps to mitigate events. The condition existed since Unit 2 startup on April 6, 2003
until completion of a modification to install an uninterruptible power source to the system
on December 7, 2003. The dominant core damage sequence of the Significance
Determination Process Phase 2 analysis was Transients without Power Conversion
System. Because the finding increased the likelihood of transients with loss of reactor
feed pumps and because the reactor feed pumps would not be available to mitigate
events, the Phase 2 analysis determined that this finding has potential safety
significance greater than very low significance.
Enforcement. No violation of regulatory requirements occurred because the reactor
feed pumps are not classified as safety-related and the UFSAR does not credit the
reactor feed pumps for abnormal operating occurrence or accident mitigation. This
issue is unresolved pending determination of the safety significance and is identified as
URI 05000324/2003006-02, Unit 2 Reactor Feed Pump Speed Control System
Modification.
1R19
Post-Maintenance Testing
a. Inspection Scope
For the post maintenance tests and maintenance activities listed below, the inspectors
reviewed the test procedure and witnessed the testing and/or reviewed test records to
confirm that the scope of testing adequately verified that the work performed was
correctly completed, and that the test demonstrated that the affected equipment was
capable of performing its intended function and was operable in accordance with TS
requirements. The inspectors reviewed the licensees actions against the requirements
in Procedure 0PLP-20, Post Maintenance Testing Program. Documents reviewed are
listed in the Attachment.
14
Enclosure
Repair EDG 4, lubricating oil low pressure switch relay (2-DG4-
LPSCR)
Unit 1A nuclear service water pump discharge check valve
refurbishment
Repair motor-driven fire pump breaker/compartment
Repair EDG 2 jet assist solenoid valve (2-DG2-6552-2)
b. Findings
No findings of significance were identified.
1R22
Surveillance Testing
a. Inspection Scope
Routine Surveillance Testing
The inspectors either observed surveillance tests or reviewed test data for the risk
significant SSC surveillances, listed below, to verify the tests met TS surveillance
requirements, UFSAR commitments, in-service testing (IST), and licensee procedural
requirements. The inspectors assessed the effectiveness of the tests in demonstrating
that the SSCs were operationally capable of performing their intended safety functions.
The inspectors reviewed the documents listed in the Attachment.
Maintenance Surveillance Test 2MST-DG22R, EDG 4 Trip Bypass Logic Test
Periodic Test 2PT-01.7, Heatup/Cooldown Monitoring, following Unit 2 reactor
trip on November 4, 2003
Periodic test 0PT-20.3, Local Leak Rate Testing, performed on Unit 2 low
pressure coolant inboard injection valve (2-E11-FO15B)
Periodic Test 0PT-12.3.2.B, Number 2 Diesel Generator Starting Air Valve
Operability Test
Inservice Surveillance Testing
The inspectors reviewed the performance of Periodic Test 0PT-09.2, High Pressure
Coolant Injection System Operability Test, performed on Unit 2. The inspectors
evaluated the effectiveness of the licensees American Society of Mechanical Engineers
(ASME)Section XI testing program to determine equipment availability and reliability.
The inspectors evaluated selected portions of the following areas: 1) testing procedures;
2) acceptance criteria; 3) testing methods; 4) compliance with the licensees IST
program, TS, selected licensee commitments, and code requirements; 5) range and
accuracy of test instruments; and 6) required corrective actions. The inspectors also
assessed any applicable corrective actions taken.
b. Findings
No findings of significance were identified.
15
Enclosure
1R23
Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed Plant Operating Manual 0PLP-22, Temporary Changes, to
assess implementation of the below listed temporary modifications. The inspectors
reviewed these temporary modifications to verify that the modifications were properly
installed and whether they had any effect on system operability. The inspectors also
assessed drawings and procedures for appropriate updating and post-modification
testing. Documents reviewed are listed in the Attachment.
ECs 5597 & 45694 - Review temporary shielding installation on the residual heat
removal (RHR) and primary containment systems
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP2
Alert and Notification System Testing
a. Inspection Scope
The inspectors ascertained the licensees commitments with respect to the testing and
maintenance of the alert and notification system (ANS), which comprised 36 sirens in
the ten-mile-radius emergency planning zone (31 in Brunswick County, 5 in New
Hanover County). The inspectors evaluated the design of the ANS, the licensees
methodology for testing the system, and the adequacy of the testing program design.
Assessment of the program as actually implemented included review of siren test
records (with an emphasis on identification of any repetitive individual siren failures),
system changes during the past two years, procedures for periodic preventative
maintenance (including post-maintenance testing), and a sample of corrective actions
and their effectiveness for siren failures and issues. The review of this program area
encompassed the period January 2002 through November 2003. Licensee procedures,
records, and other documents reviewed within this inspection area are listed in the
Attachment.
b.
Findings
No findings of significance were identified.
16
Enclosure
1EP3 Emergency Response Organization (ERO) Augmentation
a.
Inspection Scope
The inspectors identified the licensees commitments with respect to timeliness and
numbers of personnel for staffing emergency response facilities (ERFs) in the event of
an emergency declaration at Alert or higher. The licensees automated paging system
and manual backup system for call-out of ERO personnel were reviewed to determine
whether they would support staff augmentation in accordance with the criteria for ERF
activation timeliness. Methodologies for testing the primary and backup systems for
augmenting the ERO were reviewed and discussed with cognizant licensee personnel.
The inspectors also reviewed and discussed the changes to the augmentation system
and process during the past two years. The inspectors reviewed records of the last off-
hour ERO augmentation drill which involved actual travel to the plant and activation of
ERFs (conducted on April 23, 2003). Records of ERO pager tests (the backup system
for ERO notification) were reviewed. Follow-up activities for a sample of problems
identified through augmentation testing were evaluated to determine whether
appropriate corrective actions were implemented. Licensee procedures, records, and
other documents reviewed within this inspection area are listed in the Attachment.
b.
Findings
No findings of significance were identified.
1EP4 Emergency Action Level (EAL) and Emergency Plan Changes
a.
Inspection Scope
The inspectors reviewed a selected sample of changes made to the Emergency
Response Plan (ERP) since the last inspection in this program area (conducted in
November 2002) against the requirements of 10 CFR 50.54(q) to determine whether
any of the changes decreased ERP effectiveness. The subject changes, which were
incorporated in ERP Revisions 60, 61, and 62, did not include modifications to the
emergency action levels (EALs). The inspectors reviewed documentation of the
licensees 10 CFR 50.54(q) screening evaluations for Revisions 60 and 62. Licensee
procedures, records, and other documents reviewed within this inspection area are
listed in the Attachment.
b.
Findings
No findings of significance were identified.
17
Enclosure
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies
a.
Inspection Scope
The inspectors evaluated the efficacy of licensee programs that addressed weaknesses
and deficiencies in emergency preparedness. The procedure governing the plant
corrective action program was reviewed for applicability to the Emergency Preparedness
Program. Since the last inspection of this program area (conducted in November 2001),
one emergency declaration (a Notification of Unusual Event [NOUE]) was made by the
licensee, as a result of the projected threat from Hurricane Isabel on September 16,
2003. The inspectors reviewed event documentation to assess the adequacy of
implementation of ERP requirements, as well as the licensees self-assessment of ERO
performance during the event. The inspectors evaluated selected drill scenarios and
associated critiques to determine whether the licensee had properly identified failures to
implement regulatory requirements and planning standards. A sample of weaknesses
and deficiencies identified by means of these licensee processes was evaluated to
determine whether corrective actions were effective and timely. Licensee procedures,
records, and other documents reviewed within this inspection area are listed in the
Attachment.
b. Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
a. Inspection Scope
The inspectors sampled licensee submittals for the Units 1 and 2 performance indicators
(PIs) listed below for the period October 2002 through September 2003. To verify the
accuracy of the PI data reported during that period, PI definitions and guidance
contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 2, were used to confirm the reporting basis
for each data element.
Reactor Safety Cornerstone
Reactor Coolant System Specific Activity
Reactor Coolant System Leak Rate
A sample of plant records and data was reviewed and compared to the reported data to
verify the accuracy of the PIs. The licensees corrective action program records were
also reviewed to determine if any problems with the collection of PI data had occurred.
Documents reviewed are listed in the Attachment.
18
Enclosure
Emergency Preparedness Cornerstone
- Emergency Response Organization (ERO) Drill/Exercise Performance
- ERO Drill Participation
- Alert and Notification System Reliability
For the specified review period, the inspectors examined data reported to the NRC,
procedural guidance for reporting PI information, and records used by the licensee to
identify potential PI occurrences. The inspectors verified the accuracy of the PI for ERO
drill and exercise performance through review of a sample of drill and event records.
The inspectors reviewed selected training records to verify the accuracy of the PI for
ERO drill participation for personnel assigned to key positions in the ERO. The
inspectors verified the accuracy of the PI for alert and notification system reliability
through review of a sample of the licensees records of periodic system tests. The
inspectors also interviewed the licensee personnel who were responsible for collecting
and evaluating the PI data. Licensee procedures, records, and other documents
reviewed within this inspection area are listed in the Attachment.
b.
Findings
No findings of significance were identified.
4OA2 Problem Identification and Resolution
a. Inspection Scope
The inspectors performed an in-depth annual sample review of a selected AR to
determine whether conditions adverse to quality were addressed in a manner that was
commensurate with the safety significance of the issue. The inspectors reviewed the
actions taken to verify that the licensee had adequately addressed the following
attributes:
Complete, accurate, and timely identification of the problem
Evaluation and disposition of operability and reportability issues
Consideration of previous failures, extent of condition, generic or common cause
implications
Prioritization and resolution of the issue commensurate with the safety
significance
Identification of the root cause and contributing causes of the problem
Identification and implementation of corrective actions commensurate with the
safety significance of the issue
The following issue and associated corrective actions were reviewed:
AR 110705110705Actuation of the Unit 2 high pressure coolant injection system
steam exhaust rupture discs during the performance of testing
following a system maintenance outage
19
Enclosure
b. Findings and Observations
No findings of significance were identified.
4OA3 Event Follow-up
.1
All Oscillation Power Range Monitors (OPRMs) Declared Inoperable
a. Inspection Scope
On October 5, 2003, the licensee received a 10 CFR 21 notification from General
Electric that the Units 1 and 2 OPRMs have the potential for numerous, unexpected
confirmation count resets in the event of a reactor power instability condition, and were
therefore inoperable. The inspectors reviewed the licensee actions to verify proper
response in accordance with plant TS. The inspectors also reviewed the initial 10 CFR 50.72 notification to assess for appropriate reporting with established criteria.
b. Findings
No findings of significance were identified.
.2 Unit 2 Reactor Scram
a. Inspection Scope
The inspectors reviewed the licensees action in response to a Unit 2 main turbine trip
and reactor scram due to main generator loss of field that occurred on November 4, Unit
2. The loss of field was caused by the failure of the main generator alternator
brush/collector ring. During the scram all safety systems operated properly with the
exception of the 2A standby gas treatment train failing to start, the isolation of
containment isolation group 1 (main steam isolation), and the trip of the reactor feed
pumps. The licensee determined momentary degraded voltage on the AC emergency
buses (about 40% of rated) caused the relays associated with the group 1 isolation
(resulting in a loss of normal decay heat removal) and standby gas treatment fire
protection features to drop out. For further discussion of the trip of the reactor feed
pumps, see Section 1R17. In addition, the inspectors reviewed Operating Instruction
(OI) 0OI-01.06, Post Trip Review to verify the initial data gathering, equipment response
and post-trip review were conducted in accordance with the procedure requirements.
The inspectors also reviewed the initial 10 CFR 50.72 notification to verify proper
reporting with established criteria. The licensee entered this event into their corrective
action program as AR 109923109923 Licensee personnel performance is discussed in Section
1R14.
b. Findings
No findings of significance were identified.
20
Enclosure
.3 HPCI Exhaust Rupture Disc Failures
a. Inspection Scope
The inspectors reviewed the licensees response to a Unit 2 HPCI system isolation and
room fire protection actuation occurring on November 12, 2003. The actuations
occurred in response to the HPCI turbine exhaust line rupture discs actuating during
system testing. See Section 1R12.1 for further discussion of the rupture discs
actuating. The inspectors reviewed the initial 10 CFR 50.72 notification to verify proper
reporting with established criteria. The licensee entered this event into their corrective
action program as AR 110705110705
b. Findings
No findings of significance were identified.
.4 New Hanover County Sirens
a. Inspection Scope
The inspectors reviewed the licensees actions in response to the New Hanover County
emergency sirens not responding from the county emergency operations center on
November 12, 2003. The sirens were subsequently tested from the Emergency Offsite
Facility. The cause was determined to be due to radio frequency interference. Testing
to demonstrate the sirens could be successfully initiated from the county facility was
completed. The inspectors reviewed the licensees 10 CFR 50.72 notification against
established reporting criteria. The licensee entered the event into the corrective action
program as AR 110623110623
b. Findings
No findings of significance were identified.
4OA4 Cross Cutting Aspects of Findings
Section 1R12 describes a finding for the failure to position a HPCI system valve in
accordance with a clearance order following maintenance activities. The finding is
related to the cross-cutting aspect of Human Performance because the cause was
determined to be due to plant operators using improper techniques in verifying the
valves position. Other contributing causes including operator knowledge deficiencies of
valve operation, failing to perform an independent check of valve position, and the pre-
job briefs limited scope were also related to Human Performance.
21
Enclosure
4OA6 Meetings, Including Exit
On December 18, 2003, the resident inspectors presented the inspection results to
Mr. C. J. Gannon and other members of his staff. The inspectors confirmed that
proprietary information was not provided or examined during the inspection.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by the
licensee and is a violation of NRC requirements which meets the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.
10 CFR 50.74 requires in part that each licensee shall notify the commission in
accordance with section 50.4 within 30 days of the following in regard to a licensed
operator or senior operator ... (c) permanent disability or illness as described in 10CFR 55.25 of this chapter. Contrary to this, in June of 2001 a licensed operator had a
change in medical condition as described in ANSI/ANSA 3.4-1983, that was not reported
to the commission within 30 days. This finding was identified by the licensee during an
audit of medical records in April 2003. The NRC was notified of this finding in a letter
dated April 21, 2003. The licensed individual was administratively restricted to no solo
operation on April 4, 2003. The finding is of very low safety significance because
records indicate that the individual did not stand solo watch while performing licensing
duties after the change in medical condition occurred. This issue is documented in
licensee correction action request number 8992.
ATTACHMENT : SUPPLEMENTAL INFORMATION
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
E. Atkinson, Supervisor - Emergency Preparedness
A. Brittain, Manager - Security
E. Conway, Senior Nuclear Security Specialist
W. Dorman, Manager - Nuclear Assessment
C. Elberfeld, Lead Engineer, Technical Support
C. Gannon, Site Vice President (former Director - Site Operations)
J. Gawron, Training Manager
D. Hinds, Plant General Manager (former Engineering Manager)
J. Keenan, Past Site Vice President
D. Makosky, Lead Nuclear Security Specialist
W. Noll, Director - Site Operations (former Plant General Manager)
E. ONeil, Manager - Site Support Services
E. Quidley, Manager - Outage and Scheduling
H. Wall, Manager - Maintenance
M. Williams, Manager - Operations
NRC Personnel
P. Fredrickson, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Unit 2 Reactor Feed Pump Speed Control System
Modification (Section 1R17)
Opened and Closed
Failure to Position HPCI System Valve in Accordance with
Clearance Order (Section 1R12)
Closed
NONE
Discussed
NONE
2
LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
Plant Operating Manual (POM), Volume VII, Operating Instruction 0OI-01.03, Non-Routine
Activities
POM, Volume XII, Preventive Maintenance, 0PM-HT001, Preventive Maintenance on Plant
Freeze Protection and Heat Tracing System
System Description SD-53, Freeze Protection and Heat Tracing System
Section 1R04: Equipment Alignment
Procedures
Administrative Procedure ADM-NGGC-0106, Configuration Management Program
Implementation
POM, Volume III, 2OP-10, High Pressure Coolant Injection System Operating Procedure
POM, Volume III, 1OP-43, Service Water System Operating Procedure
POM, Volume III, 2OP-16, Reactor Core Isolation Cooling System Operating Procedure
Section 1R05: Fire Protection
Procedures
POM, Volume XIX, Prefire Plan, 1PFP-RB and 2PFP-RB, Reactor Building Prefire Plans
POM, Volume XIX, Prefire Plan, 0PFP-DG, Diesel Generator Building Prefire Plans
Reports
Analysis No. BNP-E-9.004, Safe Shutdown Analysis Report
Section 1R06: Flood Protection Measures
Miscellaneous Documents
UFSAR section 3.4.1, Protection From External Flooding
UFSAR section 3.4.2, Protection From Internal Flooding
Design Basis Document (DBD)-106, Hazards Analysis
DBD-105, Postulated Pipe Failure
BNP Maintenance Rule a(1) System Action Plan For Site Cables Within Manholes (system
5259)
Maintenance Rule Expert Panel Meeting Minutes System 5259 (11/19/02 - 11/19/03)
3
Work Orders
47043, Functional test of flood status level switches for DG 1 and 2 fuel oil tank rooms
47102, Functional test of flood status level switches for DG 4 fuel oil tank room
45871, Functional test of DG 1 pipe trench level switches
45867, Functional test of DG 2 pipe trench level switches
172678,Functional test of DG 4 pipe trench water level switches
46974, Functional test of service water intake structure level switch
46091, Functional test of flood status level switches (Unit 1 core spray (CS) rooms, residual
heat removal (RHR) rooms, and high pressure coolant injection (HPCI) room)
180508, Functional test of flood status level switches (Unit 2 CS rooms, RHR rooms, and HPCI
room)
Corrective Action Documents
54376, DG1 jacket water cooler service water supply valves leak by
66048, Functional test of diesel generator building cell trench flood level switches
88221, Storm drain basin overboard valves open due to weather
94558, Pump unplugged allowing floor area to flood
98218, Oil and water leak on floor of heater drain pump room Unit 1
Procedures
0AI-68, Brunswick Nuclear Plant Response to Severe Weather Warnings
0AOP-13.0, Operation During Hurricanes
0MST-Flood11Q, Flood Protection Intake Canal Level Channel Functional
0OP-47, Floor and Equipment Drain System Operating Procedure
Alarm Response Procedures
1(2)APP-UA-01 3-8, SW INTAKE STRC SUMP LEVEL HI-HI
1(2)APP-UA-28 3-5, SW INTAKE STRUCTURE FLOOD LVL HI
1(2)APP-UA-24 6-8, INTAKE CANAL FLOOD LEVEL HI
1(2)APP-UA-06 3-3, DRAINAGE BASIN TROUBLE
1(2)APP-UA-12 2-1, NORTH CS RM FLOOD LEVEL HI
1(2)APP-UA-12 1-1, NORTH CS RM FLOOD LEVEL HI-HI
1(2)APP-UA-12 2-3, SOUTH CS RM FLOOD LEVEL HI
1(2)APP-UA-12 1-3, SOUTH CS RM FLOOD LEVEL HI-HI
1(2)APP-UA-12 2-2, NORTH RHR RM FLOOD LEVEL HI
1(2)APP-UA-12 1-2, NORTH RHR RM FLOOD LEVEL HI-HI
1(2)APP-UA-12 2-4, SOUTH RHR RM FLOOD LEVEL HI
1(2)APP-UA-12 1-4, SOUTH RHR RM FLOOD LEVEL HI-HI
1(2)APP-UA-12 2-5, HPCI ROOM FLOOD LEVEL HI
1(2)APP-UA-12 1-5, HPCI ROOM FLOOD LEVEL HI-HI
1(2)APP-UA-28 3-6, DG NO 1 FUEL TNK RM FLOOD LVL HI
1(2)APP-UA-28 3-7, DG NO 2 FUEL TNK RM FLOOD LVL HI
1(2)APP-UA-28 3-8, DG BLDG BASEMENT FLOOD LVL HI
1(2)APP-UA-28 4-5, DG BLDG VALVE PIT FLOOD LVL HI
1(2)APP-UA-28 4-6, DG NO 3 FUEL TNK RM FLOOD LVL HI
4
1(2)APP-UA-28 4-7, DG NO 4 FUEL TNK RM FLOOD LVL HI
1(2)APP-UA-28 5-6, TURB BLDG PIPE TUNNEL FLOOD LVL HI
1(2)APP-UA-28 5-7, TURB BLDG PIPE TUNNEL FLOOD HI-HI
1(2)APP-UA-28 5-8, DG NO 1 PIPE TRENCH FLOOD LEVEL HI
1(2)APP-UA-28 5-9, DG NO 2 PIPE TRENCH FLOOD LEVEL HI
1(2)APP-UA-28 6-8, DG NO 3 PIPE TRENCH FLOOD LVL HI
1(2)APP-UA-28 6-9, DG NO 4 PIPE TRENCH FLOOD LVL HI
Section 1R07: Heat Sink Performance
Procedures
POM, Volume X, OMST-DG501R3, Emergency Diesel Generators 72 Month Inspection
Work Order
WO 453062-01, 2-DG4-ENG Turbocharger Intercooler Cover
Section 1R11: Licensed Operator Requalification
Procedures and Logs
POM, Volume I, Book 3, Training Program Procedure 0TPP-200, Licensed Operator Continuing
Training Program
Conduct of Examinations, TAP - 403, Rev. 6
Initial Licensing and Continued Training - Annual/Biannual Examination Development, TAP-411
License Activation and Maintenance; 0OI-01.05, Rev. 10
Licensed Operator Continued Training Program, TAP - 200, Rev. 2
Logs Recent Changes to BNP Simulator Logs
Medical Records
Operation Logs
Reactivation Records
Reactivity Anomaly Check; OPT-14.5.2, Rev. 34
Simulator Change Reports
Simulator Operation and Maintenance, TAP-412, Rev. 0
Simulator Service Request (SSR)
Simulator Test Procedure; STP-SS-002; 50% Power Steady State Comparison, Rev. 9
Simulator Program, OTPP-206, Rev. 1
Training Administration Procedure (TAP) 409, Conduct of Simulator Training and Evaluation
U1 Core Model Upgrade Report (B1C14)
U2 Core Model Upgrade Report (B2C16)
5
Section 1R12: Maintenance Effectiveness
Corrective Action (CR/AR) Reports
5051, instrument air repetitive MPFFs
22366, missed A(1) Assessment for system 5045
46853, isolated-phase bus system is not monitored in accordance with plan
46855, missed unavailability events
46857, three functional failures not logged in the MR data base
46861, AR investigation of improperly answered MR functional failure question
47884, coupling failed on Unit 1 service air dryer
48428, system 3080 has a condition monitoring criteria that was not being monitored
48432, scoping for Nuclear Boiler Instrumentation not adequate for assigning functional failures
48443, a missed functional failure in system 1080 was identified
54595, binding of transmitter 2-B21-LT-N024B-2
58722, 1-B21-F022B would not pressurize
71058, 1-iso-ph-cool-fan-2 tripped
86919, 2-B21-F028A would not pressurize
Administrative Procedures
NGGC-ADM-0101, Maintenance Rule Program, Rev. 16
Miscellaneous
BNP-PSA-056, PSA Evaluation of Maintenance Rule Performance Criteria, Unit 0, Rev. 0
Self Assessment Report 27639, dates July 23-26, 2001
Self Assessment Report 27639, dates July 22-25, 2002
1R13: Maintenance Risk Assessments and Emergent Work Evaluation
Procedures
POM, Volume 0AI-81, Water Chemistry Guidelines
Procedure OAP-025, BNP Integrated Scheduling
Technical Requirements Manual (TRM) 5.5.13, Configuration Risk Management Program
1R14: Operator Performance During Non-Routine Evolutions and Events
Procedures
Emergency Operating Procedure, 2EOP-01-RSP, Reactor Scram Procedure
POM Volume IV, General Operating Procedure, 0GP-2, Approach to Criticality and
Pressurization of the Reactor
6
Section 1R15: Operability Evaluations
Procedures
POM, Volume X, 0MST-BATT11Q, Batteries, 125 VDC, Quarterly Operability Test
POM, Volume XII, 0MMM-055, Cleanliness and Flushing Requirement
Section 1R19: Post Maintenance Testing
Procedures
POM, Volume X, OPT-34.1.1.0, Fire Pump Test (Motor-Driven and Engine-Driven)
POM, Volume X, 1PT-24.1-1, Service Water Pump and Discharge Valve Operability Test
POM, Volume X, 2MST-DG22R, DG-4 Trip Bypass Logic Test
POM, Volume XII, 0MMM-055, Cleanliness and Flushing Requirements
POM, Volume XII, 0MMM-015, Operation and Inspection of Cranes and Material Handling
Equipment
POM, Volume XII, 0CM-VCK506, Technocheck Check Valves
Section 1R22: Surveillance Testing
Procedures
POM, Volume X, 0PT-20.7B, Pressure Isolation Valve Leak Rate Test in Conjunction with RPV
Pressure Test
Section 1R23: Temporary Plant Modifications
Engineering Service Requests
ESR 00-00291, Rev. 0, Radioactive Floor Drains System
ESR 00-00291, Rev. 1, Fuel Pool Cooling & Supplemental Cooling
Sections 1EP2 - 1EP5: Reactor SafetyEmergency Preparedness
Plans and Procedures
BNP Siren Preventative Maintenance Checklist (no effective date or procedure number)
BNP Maintenance and Testing of Sirens - Customer/Supplier Agreement, 06/27/2003
CAP-NGGC-0200, Corrective Action Program, Rev. 9
Emergency Response Plan, Rev. 60 (effective 02/19/2003), Rev. 61 (effective 06/03/2003),
and Rev. 62 (effective 07/31/2003)
0PEP-02.1.1, Emergency Control - Notification of Unusual Event, Alert, Site Area Emergency,
and General Emergency, Rev. 9
0PEP-02.6.21, Emergency Communicator, Rev. 42
0PEP-02.6.26, Activation and Operation of the Technical Support Center, Rev. 13
0PEP-02.6.27, Activation and Operation of the Emergency Operations Facility, Rev. 15
0PEP-03.8.2, Personnel Accountability and Evacuation, Rev. 16
7
0PEP-04.2, Emergency Facilities and Equipment, Rev. 27
0PEP-04.3, Performance of Training, Exercises, and Drills, Rev.16
0PEP-04.7, Brunswick Emergency Notification (Automated Telephone) System, Rev. 4
REG-NGGC-0010, 10 CFR 50.59 and Selected Regulatory Reviews, Rev. 5
Siren Control System Manual (Motorola document, June 1999)
Records and Data
BNP Siren Preventative Maintenance Checklists dated 11/05/2002 (sirens 27, 28, 29)
and 07/07/2003 (siren 10)
CP&L Brunswick Steam Electric Plant Siren System Test Reports for biweekly silent tests
(01/10/2002 - 12/01/2003), quarterly growl tests (01/07/2002, 04/08/2002, 07/08/2002,
10/07/2002, 01/13/2003, 04/14/2003, 07/17/2003, 10/13/2003) and annual full-volume
tests (11/06/2002, 11/12/2003)
Critique Report on 04/23/2003 Augmentation Drill, 04/25/2003
09/17/2003 NOUE Critique Report-Hurricane Isabel, 10/24/2003
Records of ERO pager tests, 01/2002 - 11/2003 (performed monthly through 06/2003,
then quarterly)
REG-NGGC-0010, Attachment 2, 10 CFR 50.54(q) Emergency Preparedness Program
Evaluation for ERP Rev. 60 (ID No. 03-0170) and Rev. 62 (ID No. 03-1007)
Unit 2 Operator Log for September 16-18, 2003
Audits and Self-Assessments
Nuclear Assessment Section (NAS) Assessment No. B-EP-02-01, Emergency Preparedness
Assessment, 01/06/2003
Self-Assessment No. AR 79474, Emergency Preparedness Response to Security Events
(conducted 06/23-26/2003)
Self-Assessment No. AR 79476, Evaluate Effectiveness of 2003 EP Team Training Drill Cycle
(conducted 10/27-30/2003)
Action Requests (Corrective Action Documents)
Action Request (AR) 79138, NAS Assessment No. B-EP-02-01 identified examples where
positions were staffed with non-qualified individuals, 12/10/2002
AR 00083236, CPLDOSE problems on Control Room computers, 01/30/2003
AR 00083532, ERO suspensions due to lapsed qualifications, 02/03/2003
AR 00085594, EP drill weakness: Alternate EOF competes for equipment use, 02/15/2003
AR 00091046, Brunswick Emergency Notification System unavailable, 04/21/2003
AR 00095497, EP drill 05/27/2003: Items for management consideration, 06/06/2003
AR 00100005, EP drill 07/15/2003: TSC weakness, 07/17/2003
AR 00110343. Hurricane Isabel: Items for management consideration, 11/04/2003
AR 00110623, Failure of New Hanover sirens during full volume testing, 11/12/2003
AR 00112517, Alert and Notification System process enhancement, 12/04/2003
AR 00112518, Alternate EOF augmentation goals, 12/04/2003
AR 00112529, Evaluate documenting offsite assembly area locations, 12/04/2003
8
Section 4OA1: Performance Indicator Verification
Procedures
POM, Vol. VII, 1OI-03.1, Control Operator Daily Surveillance Report
POM, Vol. VII, 2OI-03.1, Control Operator Daily Surveillance Report
Reactor coolant radiochemistry logs
Records and Data
CP&L Brunswick Steam Electric Plant Siren System Test Reports for biweekly silent tests
(01/10/2002 - 12/01/2003), quarterly growl tests (01/07/2002, 04/08/2002, 07/08/2002,
10/07/2002, 01/13/2003, 04/14/2003, 07/17/2003, 10/13/2003) and annual full-volume
tests (11/06/2002, 11/12/2003)
Documentation packages (scenario/time line/event notification forms/critique report) for ERO
drills on 10/15/2002 and 05/27/2003
Documentation packages (event notification forms/evaluator critique) for Licensed Operator
Continuing Training drills on 02/23/2003, 06/09/2003, 06/16/2003, 06/23/2003, and 06/30/2003
EPL-001, Emergency Phone List, 09/30/2003
ERO participation rosters (source record) for 05/27/2003 drill
Section 4OA3: Event Followup
Procedures
POM, Volume VII, Operating Instructions 0OI-01.07, Notifications, Rev. 11