ML032900004
| ML032900004 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 10/16/2003 |
| From: | Fredrickson P NRC/RGN-II/DRP/RPB4 |
| To: | Keenan J Carolina Power & Light Co |
| References | |
| IR-03-005 | |
| Download: ML032900004 (23) | |
See also: IR 05000324/2003005
Text
October 16, 2003
Carolina Power and Light Company
ATTN: Mr. J. S. Keenan
Vice President
Brunswick Steam Electric Plant
P. O. Box 10429
Southport, NC 28461
SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION
REPORT NOS. 05000325/2003005 AND 05000324/2003005
Dear Mr. Keenan:
On September 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 September 17, 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.
The report documents one NRC-identified 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. If you contest the non-cited violation, you should provide a response
within 30 days of the date of this inspection report, with the basis for your denial, to the 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.
CP&L 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, 324/2003005
w/Attachment: Supplemental Information
cc w/encl: (See page 3)
CP&L 3
cc w/encl:
C. J. Gannon, Director Peggy Force
Site Operations Assistant Attorney General
Brunswick Steam Electric Plant State of North Carolina
Carolina Power & Light Electronic Mail Distribution
Electronic Mail Distribution
Robert P. Gruber
W. C. Noll Executive Director
Plant Manager Public Staff NCUC
Brunswick Steam Electric Plant 4326 Mail Service Center
Carolina Power & Light Company Raleigh, NC 27699-4326
Electronic Mail Distribution
Public Service Commission
James W. Holt, Manager State of South Carolina
Performance Evaluation and P. O. Box 11649
Regulatory Affairs CPB 7 Columbia, SC 29211
Carolina Power & Light Company
Electronic Mail Distribution David R. Sandifer, Chairperson
Brunswick County Board of
Edward T. ONeil, Manager Commissioners
Site Support Services P. O. Box 249
Carolina Power & Light Company Bolivia, NC 28422
Brunswick Steam Electric Plant
Electronic Mail Distribution Dan E. Summers
Emergency Management Coordinator
New Hanover County Department of
Leonard Beller, Supervisor Emergency Management
Licensing/Regulatory Programs P. O. Box 1525
Carolina Power and Light Company Wilmington, NC 28402
Electronic Mail Distribution
Steven R. Carr
Associate General Counsel - Legal Dept.
Progressive Energy Service Company, LLC
P.O. Box 1551
Raleigh, North Carolina 27602-1551
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
B. Mozafari, NRR
L. Slack, RII EICS
RIDSNRRDIPMLIPB
PUBLIC
OFFICE DRP/RII DRP/RII DRP/RII DRP/RII
SIGNATURE GTM JDA JAC6 EMD
NAME GMacdonald:as JAustin JCanady EDiPaolo
DATE 10/16/2003 10/16/2003 10/16/2003 10/16/2003
E-MAIL COPY? YES NO YES NO YES NO
PUBLIC DOCUMENT YES NO
OFFICIAL RECORD COPY DOCUMENT NAME: C:\ORPCheckout\FileNET\ML032900004.wpd
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-325, 50-324
Report Nos: 05000325/2003005 and 05000324/2003005
Licensee: Carolina Power and Light
Facility: Brunswick Steam Electric Plant, Units 1 & 2
Location: 8470 River Road SE
Southport, NC 28461
Dates: June 22, 2003 - September 20, 2003
Inspectors: E. DiPaolo, Senior Resident Inspector
J. Canady, Acting Senior Resident Inspector
J. Austin, Resident Inspector
Approved by: Paul Fredrickson, Chief,
Reactor Projects Branch 4
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000325/2003-005, 05000324/2003-005; 06/22/2003 - 09/20/2003; Brunswick Steam
Electric Plant, Units 1 and 2; Problem Identification and Resolution.
The report covered a three-month period of inspection by resident inspectors. 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: Initiating Events and Mitigating Systems
Green. The inspectors identified a non-cited violation for the licensees failure to comply
with 10 CFR 50, Appendix B, Criterion XVI. This violation is related to inadequate
corrective actions to prevent recurring nuclear and conventional service water pump
functional failures caused by clogging of the associated pumps strainer due to marine
growth in the service water intake bays. This resulted in six failures in twelve months.
This finding is greater than minor because it resulted in an increase in the likelihood of
loss of nuclear and conventional service water initiating events. In addition, the finding
affected the operability, availability, and reliability of the nuclear and conventional
service water pumps. The finding is of very low safety significance because redundancy
existed in the nuclear and conventional service water systems and the relatively short
duration of unavailability of the pumps. (Section 4OA2)
B. Licensee Identified Violations
None.
REPORT DETAILS
Summary of Plant Status
Unit 1 began the report period operating at full power. On July 1, 2003, the unit was shutdown
for a forced outage due to drywell unidentified leakage exceeding Technical Specification (TS)
requirements. The Unit was returned to full power on July 6, following drywell leakage repairs.
On July 11, reactor power was reduced to 70% power to facilitate repairs of a steam leak on the
B feedwater heater string. Full power was reached the following day, and the Unit remained at
approximately full power for the remainder of the inspection period.
Unit 2 began the report period operating at full power. Power was reduced to approximately
50% on August 22 for a rod sequence exchange, various planned corrective and preventive
maintenance activities, and surveillance testing. Power was returned to full power on
August 25, and the Unit remained at approximately full power for the remainder of the
inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection
a. Inspection Scope
The inspectors reviewed the licensees preparations for severe weather conditions
during hurricane season. The inspectors toured protected area and exterior plant
grounds for loose debris which could pose hazards to plant equipment during high
winds, and reviewed preparations for increased accumulation of rain water. The
inspectors selected risk-significant and susceptible systems and areas for review.
These included the electrical switch yard, the hydrogen tank storage area, the
radioactive waste building, the emergency diesel generator building and the service
water structure.
During the approach of Hurricane Isabel to the Cape Fear Region of North Carolina, the
inspectors attended hurricane preparation status meetings and reviewed provisions for
relief of plant operators, security guards, and emergency response organization
personnel. Licensee preparations for plant damage assessment were also reviewed.
On September 17 and 18, 2003, the inspectors observed the licensees emergency
response facility staffs monitoring of storm conditions, damage assessment and
corrective actions.
During these inspections, the following procedures were reviewed to verify that the
licensees actions were consistent with severe weather program requirements:
- Plant Emergency Procedure 0PEP-02.6, Severe Weather
- Administrative Instruction 0AI-68, Brunswick Nuclear Plant Response to Severe
Weather Warning
- Abnormal Operating Procedure 0AOP-13.0, Operation During Hurricane, Flood
Conditions, Tornado, or Earthquake
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b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
a. Inspection Scope
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 verified that the licensee identified and resolved
equipment alignment problems that could cause initiating events or impact mitigating
system availability. Administrative procedure ADM-NGGC-0106, Configuration
Management Program Implementation, was reviewed by the inspectors to verify that
available structure, system or components (SSCs) met the requirements of the
licensees configuration control program.
- Units 1 and 2 offsite circuit breaker alignment (emergency diesel generator
number 3 OOS due to maintenance)
- Unit 2 core spray train A (B train OOS due to maintenance)
- Unit 1 reactor core isolation cooling (RCIC)
In determining correct system lineup, the inspectors reviewed Procedure OPT-12.8.1,
Breaker Alignment Operability Test, 2OP-18, Core Spray System Operating Procedure,
and 1OP-16, Reactor Core Isolation Cooling (RCIC) System Operating Procedure.
b. Findings
No findings of significance were identified.
1R05 Fire Protection
1. Fire Area Walkdowns
a. Inspection Scope
The inspectors reviewed current action requests (ARs) and work orders (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 the
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associated Prefire Plans to verify that the requirements for fire protection design
features, fire area boundaries, and combustible loading were met:
- Unit 1 reactor building, -17-foot elevation, high pressure coolant injection room
and the north and south residual heat removal (RHR) rooms, Prefire Plan
1PFP-RB, Reactor Building Prefire Plans (three areas)
- Unit 1 reactor building, nine and 20 foot elevations, north and south RHR heat
exchanger rooms, Prefire Plan 1PFP-RB, Reactor Building Prefire
Plans (2 areas)
- Diesel generator building number two cell, 23-foot elevation. Prefire plan
OPFP-DG Diesel Generator Building Prefire Plans
- Units 1 and 2 reactor building, 23-foot elevation, battery rooms 1A, 1B, 2A, and
2B, Prefire Plan 0PFP-CB, Control Building Prefire Plans (four areas)
To assess the licensees ability to identify and correct adverse conditions, the inspectors
reviewed the licensees actions in response to AR 102494102494which identified incorrect test
requirements for the station emergency lighting unit batteries.
b. Findings
No findings of significance were identified.
2. Fire Drill
a. Inspection Scope
On September 5, 2003, the inspectors observed an unannounced plant fire drill in the
Unit 2 reactor building, to assess the fire brigade performance and to verify that proper
firefighting techniques for the type of fire encountered were utilized. The inspectors
monitored the fire brigades use of protective equipment and firefighting equipment to
verify that preplanned firefighting procedures and appropriate firefighting techniques
were used, and to verify that the directions of the fire brigade leader were thorough,
clear, and effective. The inspectors attended the critique to confirm that appropriate
feedback on performance was provided to brigade members and to ensure that areas
for improvement were properly identified for licensee follow-up. In preparing for and
evaluating the drill the inspectors reviewed the preplanned drill scenario, Drill Number
99-F-RB-02 (Fire in Motor Control Center 2XDA), and the fire plan for the area as
documented in 2PFP-RB, Reactor Building Prefire Plans.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
b. Inspection Scope
The inspectors observed licensed operator performance and reviewed the associated
training documents during simulator training sessions for cycle 2003-04. This simulator
4
observation and review included an evaluation of emergency operating procedure and
abnormal operating procedure utilization. The inspectors reviewed Procedure OTPP-
200, Licensed Operator Continuing Training (LOCT) Program, to verify that the program
ensures safe power plant operation. The scenarios tested the operators ability to
respond to a hydraulic control unit low pressure, a conventional service water leak,
failure of an electro-hydraulic control pressure regulator, failure of the reactor protection
system to scram, loss of 4 kilovolt buses 2D and 3E, and a large break loss of coolant
accident. The inspectors reviewed the operators activities to verify 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 TS actions,
regulatory reports, and notifications, were observed. The inspectors reviewed simulator
scenario LORX-12 which documented the associated observed simulator training
scenario.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
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 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.
valves 2717 and 2720 failures to stoke fully
- Work Request 107490 - Radioactive waste effluent monitor failure during effluent
release
b. Findings
No findings of significance were identified.
5
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 using Procedure
OAP-025, BNP Integrated Scheduling and Technical Requirements Manual (TRM)
5.5.13, Configuration Risk Management Program. 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 work orders for the following
OOS equipment:
- AR 98294 Failure of torus purge exhaust valve (1-CAC-V7) to meet
in-service test stroke time requirements results in a yellow
risk window due to the unavailability of the large
suppression pool vent and hardened wetwell vent paths
in a yellow risk window
- 0MST-DG501R3 Preplanned 72-month inspection of emergency diesel
generator (EDG) #3 results in a yellow risk window, BNP
Risk Profile Week 29
- AR 102967102967 Vital battery 1A-1 cell #53 inoperable resulting in deferral
of EDG #4 planned outage during work week 34
- AR 103914103914 Unit 2 A 250-volt battery positive bus ground and
subsequent troubleshooting activities occurring on
September 7, 2003
- 1 HPCI 37 Unit 1 high pressure coolant injection system outage work
scope reduction due to the approach of Hurricane Isabel
during Work Week 37
- AR 104887104887 Vital battery 1A-2 declared inoperable due to cell #42 not
meeting TS 3.8.6 Category C limits
b. Findings
No findings of significance were identified.
1R14 Operator Performance During Non-Routine Plant Evolutions and Events
a. Inspection Scope
The inspectors observed and monitored Unit 1 control room personnel actions during
the power decrease and ascension associated with the forced outage on July 1, 2003,
due to drywell leakage in excess of that allowed by TS. Operator actions were observed
prior to the forced outage during drywell valve back seating efforts to mitigate the
leakage. The purpose of the review was to verify the following: (1) the power changes
were performed in accordance with Procedure 0GP-12, Power Changes, (2) the
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appropriate TS was entered during the back seating activities, and (3) control room
operations personnel were provided with guidance on the control of plant equipment and
system status in accordance with Operating Instruction 0OI-01.08, Control of Equipment
and System Status.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the operability evaluations associated with six issues, listed
below, 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.
to address potential vortexing and air entrainment while aligned to
the condensate storage tank as a suction source
- AR 99205 Coolant leak from motor-driven fire pump heat exchanger
- AR 98448 2A conventional service water pump blowdown strainer clogged
system to Quality Class B
b. Findings
No findings of significance were identified.
1R16 Operator Work-Arounds (OWAs)
a. Inspection Scope
The inspectors reviewed the status of OWAs for Units 1 and 2 to determine if the
functional capability of the system or operator reliability in responding to an initiating
event was 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.
7
The two OWAs reviewed were:
- OWA-403, Auxiliary Operator or Instrumentation and Control Technician Isolate
Three High Pressure Oil Switches Prior to Resetting a Reactor Feedwater Pump
Turbine or Starting a Reactor Feedwater Pump Turbine Oil Pump. A
modification on Unit 2 has replaced switches and the Unit 1 Modification will be
performed in the 2004 outage (See Integrated Inspection Report Numbers 50-
325/03-03 and 50-324/03-03)
- OWA-375, Leak By Valves Upstream of Feedwater Stop Valve Causes Rapid
Injection of Cold Water when Opening per GP-02
b. Findings
No findings of significance were identified.
1R17 Permanent Plant Modifications
a. Inspection Scope
The inspectors reviewed a permanent plant modification (WO 326591) that removed
pneumatic controls located in the E3 switchgear room and replaced them with a
temperature switch. The inspectors reviewed the design adequacy of the modification
for material compatibility which included functional properties, environmental
qualification, and seismic evaluation. One purpose of the review was to verify that the
replacement switch performance characteristics met the design bases and the design
assumptions. Another purpose was to verify that modification preparation, staging, and
implementation did not impair emergency/abnormal operating procedure actions and
key safety functions. The inspectors also reviewed the modification to verify that the
post-modification testing would establish operability and that unintended system
interactions would not occur, and that testing demonstrated that the modification
acceptance criteria were met.
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.
- 0PT-07.1.8, Core Spray System Component Test following preventive
maintenance on Unit 2 B core spray system
on Unit 2 RCIC
8
- 0PT-15.7, Standby Gas Treatment System Operability Test following
maintenance on system damper 1-VA-1D-BFV-RB-MO per WO 71178
replacement on scram solenoid pilot valves 2-C12-SV-117/118 (Unit 2 control
2717 following circuit board replacement
- AR 98654, post-maintenance test of the battery charger amplifier board
replacement
b. Findings
No findings of significance were identified.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
The inspectors monitored portions of the Unit 1 TS required shutdown that commenced
on June 30, 2003, due to high drywell unidentified leakage. The inspectors verified that
the requirements of General Plant Operating Procedure 0GP-05, Unit Shutdown, were
met. Additionally the inspectors reviewed the data package of Procedure 1PT-01.7,
Heatup/cooldown Monitoring, to verify that vessel cooldown rates were not exceeded.
The inspectors monitored the heatup and startup activities following the Unit 1 forced
outage. The inspectors reviewed Procedures 0GP-01, Pre-startup Checklist, and 0GP-
02, Approach to Criticality and Pressurization of the Reactor to ensure that control room
operators satisfied procedural requirements. In addition, the inspectors reviewed TS,
license conditions, commitments, and administrative procedural prerequisites for mode
changes to verify that the requirements for changing the plant configurations were met.
The changing plant configurations observed by the inspectors included the reactor
startup, the approach to criticality, and portions of the power ascension.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
1. Routine Surveillance Testing
a. Inspection Scope
The inspectors either observed surveillance tests or reviewed test data for the risk
significant SSC surveillance 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.
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- Periodic Test 1PT-01.7, Heatup/cooldown Monitoring
Unit 2
- Periodic Test OPT-12.2B, EDG #2 monthly load test
b. Findings
No findings of significance were identified.
2. Inservice Surveillance Testing
a. Inspection Scope
The inspectors observed the performance of Periodic Test 0PT-08.2b, Low Pressure
Coolant Injection (LPCI)/Residual Heat Removal (RHR) Operability Test-Loop B,
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 in-service testing 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.
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.
- PCHG-DESG Engineering Change (EC) 52293, temporary cover installation on
phase B isophase bus duct
b. Findings
No findings of significance were identified.
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Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors observed two site emergency preparedness training evolutions
conducted on July 15, 2003, and September 2, 2003. The inspectors reviewed the drill
scenarios narrative to identify the timing and location of classification, notification, and
protective action recommendation (PAR) development activities. The inspectors
evaluated each drills conduct from the control room simulator, technical support center,
and the emergency operations facility. During the drills, the inspectors assessed the
adequacy of event classification and notification activities. The inspectors observed the
licensees post-drill critiques and evaluated the licensees self assessments of
classification, notification, and protective action recommendation development. The
inspectors assessed the licensees evaluation of each drills performance with respect to
performance indicators. To assess the ability of the licensee to identify and correct
problems the inspectors reviewed ARs 105705 and 105706 which documented drill
performance deficiencies and improvement items from the observed drill.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification
a. Inspection Scope
The inspectors reviewed the performance indicator (PI) data submitted in July 2003 to
the NRC since the last verification inspection was performed. A sample of plant records
and data was reviewed and compared to the reported data to verify the accuracy of the
performance indicators. The licensees corrective action program records were also
reviewed to determine if any problems with the collection of PI data had occurred. PI
definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 2 were utilized.
The inspectors reviewed the following Units 1 and 2 PIs for the period July 2002 to June
2003:
- Safety System Unavailability, Reactor Core Isolation Cooling
- Safety System Unavailability, Residual Heat Removal System
- Safety System Functional Failures
The following documents were reviewed:
- Control room operating logs
- NRC inspection reports issued during the review period
11
- Licensees data bases for the PIs listed above
- Nuclear Generating Group Standard Procedure REG-NGGC-0009, NRC
Performance Indicator
- NEI 99-02 Regulatory Assessment Performance Indicator Guideline
- Licensee Event Reports
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 selected ARs 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 issues and associated corrective actions were reviewed:
- AR 74020 Service water pump strainer functional failures due to high
strainer differential pressure
- AR 88634 Unit 2 main steam line drain isolation valve local leak rate test
failures
c. Findings and Observations
Introduction: A Green NCV was identified for inadequate corrective actions to prevent
the recurrence of service water pump discharge strainer blowdown lines from clogging.
Description: On July 8, 1999, the licensee identified a significant adverse condition
(AR 07149). The licensee noted several instances when the blowdown lines of the
service water (nuclear and conventional) pump discharge strainers became clogged with
oyster shells, rendering the pump impaired and/or inoperable. The service water pumps
are deep-well pumps and take suction on the service water intake structure bays. The
pumps provide cooling water to various safety-related (i.e. EDGs and RHR systems)
and non-safety-related loads. The licensee determined that the root cause was due to
12
inadequate cleaning of the service water pump bays, and implemented a yearly
preventive maintenance cleaning of the bays. The AR was closed on
August 24, 2000.
On October 10, 2002, the licensee identified another significant adverse condition (AR
74020), again identifying several instances of service water pump inoperabilities due to
the pump strainer blowdown line becoming clogged with oyster shells. In both of the
above mentioned issues, the licensee identified a contributing cause as the
formation/existence of oyster shells in the vicinity of the service water pump suction.
In May 2003, the inspectors questioned the status of the root cause analysis and
corrective actions of AR 74020. At that time, corrective actions had not been fully
implemented. The inspectors noted that the root cause was determined to be
inadequate cleaning of the service water pump bays. The inspectors questioned the
promptness and adequacy of the licensees corrective action plan given the fact that
three functional failures had occurred during the first three months of 2003. The
licensee subsequently reevaluated the root cause evaluation and corrective actions of
AR 74020, and identified oyster growth on the pump casings as an additional root
cause. Past cleanings of the pump bays did not include cleaning of the deep-well pump
exterior casings. The licensee implemented increased monitoring of strainer differential
pressure to detect possible blowdown line clogging at an early stage, thus reducing
pump functional failures. Additional corrective actions were planned to clean the pump
casings concurrent with bay cleanings. Other corrective actions and enhancements
were planned to improve system reliability.
Analysis: This finding is greater than minor because it resulted in an increase in the
likelihood of loss of nuclear and conventional service water initiating events. In addition,
the mitigating systems cornerstone objective to ensure reliability, availability, and
capability of systems that respond to initiating events was affected by equipment
performance. The deficiency was evaluated using the out-of-service times for the
nuclear and conventional services water pumps for the past year. A Significance
Determination Process analysis determined the finding to be of very low safety
significance (Green) due to the relatively short duration of unavailability of the pumps.
Enforcement: 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires in part,
that measures be established to assure that conditions adverse to quality are promptly
identified and corrected. In the case for significant conditions adverse to quality, the
measures shall assure the cause of the condition is determined and corrective actions
taken to preclude repetition. The corrective actions of ARs 07149 and 74020 failed to
preclude repetitive functional failures of nuclear and conventional service water pumps
due to discharge strainer blowdown line clogging. This resulted in six pump failures in a
twelve month time-frame, between October 2002 and September 2003. Because the
failure of the corrective actions to prevent repetition is of very low safety significance
and has been entered into the corrective action program (revision to AR 74020), this
violation is being treated as an NCV, consistent with Section VI.A of the NRC
Enforcement Policy: NCV 50-324,325/2003-05-01, Inadequate Corrective Actions for
Service Water Strainer Blowdown Line Clogging.
13
4OA3 Event Follow-up
1. Unusual Event Due to Hurricane Warning
a. Inspection Scope
At 10:40 p.m. on September 16, 2003, the site declared an Unusual Event due to the
issuance of a hurricane warning for the Cape Fear Region of North Carolina. The
inspectors reviewed Plant Emergency Procedure 0PEP-02.1, Initial Emergency Actions,
to verify the licensees actions to classify and make timely notification were consistent
with site emergency plan requirements. The inspectors reviewed plant status including
the availability of mitigating systems and the effect of storm conditions on the plant. The
inspectors assessed licensee performance with respect to the licensees staffing of the
emergency response organization, provisions for the relief of plant operators, and plant
damage assessment. During the approach of the storm the inspectors communicated
plant status to the Region II Incident Response Center. At 5:40 p.m. on September 18,
2003, the licensee exited the Unusual Event due to the lifting of the hurricane warning
for the Cape Fear Region. See Section 1R01 for additional inspector activities
associated with adverse weather preparations.
b. Findings
No findings of significance were identified.
2. (Closed) Licensee Event Report (LER) 50-324/2003-01: Main Steam Line Drain
Isolation Valve Local Leak Rate Test Failures. During the Spring 2003 Unit 2 refueling
outage, the results of local leak rate testing of the main stream line drain inboard and
outboard isolation valves (2-B21-F016 and 2-B21-F019) determined that the valves
would not pressurize. Due to the inability to pressurize the containment penetration, the
ability to quantify the leak rate of the penetration was beyond the ability of the licensees
test method. Therefore, the licensee conservatively assumed a direct path of a 3-inch
nominal pipe size for containment leak rate determination. This method of quantifying
the leak rate, administratively required by the licensees Appendix J program, resulted in
a calculated leak rate that exceeded the TS primary containment leak rate limit.
The outboard isolation valve was refurbished by replacing the valve steam and disc
assemblies. Only small defects of the valve disc were observed. The inboard isolation
valve, a limit-seated valve, needed only a minor limit switch adjustment to achieve
satisfactory leak rate results. Although the valves were not leak tight, the valves were
capable of closing and reducing the release of radioactive gases. Based on this
information and the demonstrated ability of the valves to close, the inspector concluded
that the method for calculating the penetration leak rate, was conservative. The valves
were classified as a(1) in the licensees Maintenance Rule Program. The licensee
planned to replace the valves with a design that will provide better isolation capability.
The licensee also planned to install an additional block valve and a test connection in
the system that will facilitate local leak rate testing. This event did not constitute a
violation of NRC requirements due to the uncertainty on when the containment
penetration leakage problems occurred, with respect to the allowed out-of-service time.
14
The licensee documented the issue in the corrective action program as AR 88364. This
LER is closed.
3. (Closed) LER 50-324/2003-02: Reactor Protection System Instrumentation Out of
Calibration Results in Operation Prohibited by Technical Specifications. During the
Spring 2003 Unit 2 refueling outage, maintenance technicians recorded as-found
calibration setpoints on four-of-eight inboard and outboard main steam isolation valve-
closure reactor protection system position limit switches exceeding the TS allowable
value. The data was collected using a new licensee calibration method which was more
repeatable and removed human factors associated with the previously used method.
The previous method, which was used to set the limit switches during previous outages,
relied on visual observations and coordination between personnel in different locations
to measure the limit switch setpoint. The inspector noted that the previous method used
by the licensee was consistent with industry practice.
The main steam isolation valve-closure reactor trip function is intended to initiate a
scram prior to a significant reduction in steam flow thus reducing the severity of the
subsequent pressure transient and its effect on fuel thermal limits. The licensees
evaluation of the as-found condition determined that the condition did not appreciable
decrease the fuel thermal margin nor did it significantly impact peak transient system
pressurization. The main steam isolation valve-closure reactor trip function is not
credited in the plants over-pressure analysis.
Because the new calibration method was not available during the previous Unit 1
outage, the inspector reviewed the licensees assessment of test data. The inspector
concluded that there was a reasonable assurance of operability for the Unit 1 limit
switches due to the existence of more margin between the as-left measured setpoint
and the TS allowable value. This event did not constitute a violation of NRC
requirements due to the uncertainty as to what effect the more conservative nature of
the revised calibration methodology had on actual as-found instrument calibration
setpoints. The licensee documented the event in the corrective action program as AR
89077. This LER is closed.
4. (Closed) LER 50-324/2003-03: Unit 2 Scram During Startup Due to Electro Hydraulic
Control (EHC) System Malfunction. The cause of the event was determined to be an
intermittent error signal from an EHC card that was improperly engaged in its hardware
slot in the EHC pressure control circuitry. The licensee found the steam line resonance
compensator (SLRC) card for the B EHC pressure regulator was not fully seated.
Although the card was not removed for maintenance during the Spring 2003 refueling
outage, other cards in the cabinet had been removed and reinstalled. Prior to operation,
all cards were checked for proper engagement. The licensees practice for verifying
proper engagement was to apply manual pressure to cards that had been removed and
perform visual inspection of all other cards. Due to the design and arrangement of the
SLRC cards, the licensee determined that manual seating and verification of proper
seating was less than optimal. The licensee planned a procedure revision to add detail
to the restoration steps for EHC cards to assure proper engagement for all cards
following maintenance activities. The LER was reviewed by the inspectors and no
findings of significance were identified. This event did not constitute a violation of NRC
15
requirements. The licensee documented the event in the corrective action program as
AR 89705. This LER is closed.
4OA5 Other
Review of World Association of Nuclear Operators (WANO) Interim Report
The inspectors reviewed a WANO Interim Report for the Brunswick Steam Electric
Plant, dated August 14, 2003. The review determined that the results of the WANO
report were generally consistent with the results of similar evaluations conducted by the
NRC. The inspectors determine that no additional Regional follow-up concerning the
results of the WANO report was warranted.
4OA6 Meetings, Including Exit
Exit Meeting Summary
On September 17, 2003, the resident inspectors presented the inspection results to
Mr. J. Keenan and other members of his staff. The inspectors confirmed that
proprietary information was not provided or examined during the inspection.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel:
A. Brittain, Manager Security
E. Conway, Senior Nuclear Security Specialist
W. Dorman, Manager Nuclear Assessment
C. Elberfeld, Lead Engineer, Technical Support
N. Gannon, Director of Site Operations
J. Gawron, Training Manager
D. Hinds, Manager Brunswick Engineering Support Section
J. Keenan, Site Vice President
D. Makosky, Lead Nuclear Security Specialist
W. Noll, Plant General Manager
E. ONeil, Manager Site Support Services
H. Wall, Manager Maintenance
E. Quidley, Manager Outage and Scheduling
M. Williams, Manager Operations
NRC Personnel:
P. Fredrickson, Branch Chief, Division of Reactor Projects (DRP), Region II (RII)
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
None
Opened and Closed
50-324,325/2003-05-01 NCV Inadequate Corrective Actions for Service Water Strainer
Blowdown Line Clogging (Section 4OA2)
Closed
50-324/2003-01 LER Main Steam Line Drain Isolation Valve Local Leak Rate
Test Failures (Section 4OA3.2)
50-324/2003-02 LER Reactor Protection System Instrumentation Out of
Calibration Results in Operation Prohibited by Technical
Specifications (Section 4OA3.3)
50-324/2003-03 LER Unit 2 Scram During Startup Due to Electro Hydraulic
Control System Malfunction (Section 4OA3.4)
Discussed
None
Attachment