ML031220563
| ML031220563 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 05/02/2003 |
| From: | Cahill S Reactor Projects Region 2 Branch 6 |
| To: | Scalice J Tennessee Valley Authority |
| References | |
| IR-03-003 | |
| Download: ML031220563 (30) | |
See also: IR 05000328/2003003
Text
May 2, 2003
Tennessee Valley Authority
ATTN: Mr.J. A. Scalice
Chief Nuclear Officer and
Executive Vice President
6A Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801
SUBJECT: SEQUOYAH NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION
REPORT 50-327/03-03 AND 50-328/03-03
Dear Mr. Scalice:
On April 5, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
the Sequoyah Nuclear Power Plant, Units 1 and 2. The enclosed report presents the results of
the integrated inspection which were discussed on April 9, 2003, with Mr. Rick Purcell and other
members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, the inspectors identified one issue of very low safety
significance (Green). This issue was determined to involve a violation of NRC requirements.
However, because of its very low safety significance and because it has been entered into your
corrective action program, the NRC is treating this issue as a non-cited violation, in accordance
with Section VI.A.1 of the NRCs Enforcement Policy. If you contest this non-cited violation, you
should provide a response with the basis for your denial, within 30 days of the date of this
inspection report to the Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington, DC 20555-0001, 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 Sequoyah facility.
TVA 2
In accordance with 10 CFR 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) components 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/
Stephen J. Cahill, Chief
Reactor Projects Branch 6
Division of Reactor Projects
Docket Nos.: 50-327, 50-328
Enclosure: NRC Inspection Report 50-327/03-03, 50-328/03-03
w/Attachment: Supplemental Information
cc w/encl: (See page 3)
TVA 3
cc w/encl: County Executive
Karl W. Singer Hamilton County Courthouse
Senior Vice President Chattanooga, TN 37402-2801
Nuclear Operations
Tennessee Valley Authority Ann Harris
Electronic Mail Distribution 341 Swing Loop
Rockwood, TN 37854
James E. Maddox, Acting Vice President
Engineering and Technical Services John D. White, Jr., Director
Tennessee Valley Authority Tennessee Emergency Management
Electronic Mail Distribution Agency
Electronic Mail Distribution
Richard T. Purcell
Site Vice President Distribution w/encl: (See page 4)
Sequoyah Nuclear Plant
Electronic Mail Distribution
General Counsel
Tennessee Valley Authority
Electronic Mail Distribution
Robert J. Adney, General Manager
Nuclear Assurance
Tennessee Valley Authority
Electronic Mail Distribution
Mark J. Burzynski, Manager
Nuclear Licensing
Tennessee Valley Authority
Electronic Mail Distribution
Pedro Salas, Manager
Licensing and Industry Affairs
Sequoyah Nuclear Plant
Tennessee Valley Authority
Electronic Mail Distribution
D. L. Koehl, Plant Manager
Sequoyah Nuclear Plant
Tennessee Valley Authority
Electronic Mail Distribution
Lawrence E. Nanney, Director
TN Dept. of Environment & Conservation
Division of Radiological Health
Electronic Mail Distribution
TVA 4
Distribution w/encl:
M. Marshall, NRR
L. Slack, RII EICS
RIDSNRRDIPMLIPB
PUBLIC
OFFICE DRP/RII DRP/RII DRP/RII DRP/RII DRSP/RII DRP/RII
SIGNATURE TCK TCK for RC TCK for SF RT
NAME TKolb:aws RCarrion SFreeman RTelson SVias
DATE 05/02/2003 05/02/2003 05/02/2003 05/02/2003 05/02/2003
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
PUBLIC DOCUMENT YES NO
OFFICIAL RECORD COPY DOCUMENT NAME: C:\ORPCheckout\FileNET\ML031220563.wpd
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-327, 50-328
Report No: 50-327/03-03, 50-328/03-03
Licensee: Tennessee Valley Authority (TVA)
Facility: Sequoyah Nuclear Plant, Units 1 & 2
Location: Sequoyah Access Road
Soddy-Daisy, TN 37379
Dates: January 5, 2003 - April 5, 2003
Inspectors: S. Freeman, Senior Resident Inspector
R. Telson, Resident Inspector
R. Carrion, Senior Project Engineer (Section 1R06)
S. Vias, Senior Reactor Inspector (Section 40A5)
Approved by: S. Cahill, Chief
Reactor Projects Branch 6
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000327-03-03, IR 05000328-03-03, Tennessee Valley Authority, 1/5/2003 - 4/5/2003
Sequoyah Nuclear Power Plant, Units 1 & 2, Operability Evaluations.
The report covered a three-month period of inspection by resident inspectors and an
announced inspection by two regional based inspectors. The significance of most findings is
indicated by their color (Green, White, Yellow, Red) using IMC 0609, "Significance
Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be
assigned a severity level after NRC management review. The NRCs program for overseeing
the safe operation of commercial nuclear power reactors is described in NUREG 1649,
Reactor Oversight Process, Revision 3, dated July 2000.
A. Inspector-Identified and Self-Revealing Findings
Cornerstone: Barrier Integrity
- Green. Inadequate technical guidance was identified because the associated
procedure did not contain the necessary steps to ensure that multiple breaches
of the shield building would be adequately controlled.
This inspector-identified finding was determined to be a non-cited violation of
(NCV) Technical Specification 6.8.1.a. It was more than minor, because if left
uncorrected it could result in the actual shield building breached area exceeding
the margin of operability for the emergency gas treatment system. The finding
also affected the configuration control attribute of the containment barrier. The
finding is of very low safety significance because the actual margin was not
exceeded. It was also considered to constitute a deficiency in the cross-cutting
element of Problem Identification and Resolution (Section 1R15 and 40A2).
B. Licensee Identified Violations
None
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at or near 100 percent rated thermal power until March 17, 2003 when it was
shut down for a scheduled refueling and steam generator replacement outage.
Unit 2 began the inspection period shutdown for repair of the Number 3 reactor coolant pump
motor. The motor was repaired and the unit returned to 100 percent power on January 8, 2003.
The unit operated at or near 100 percent rated thermal power until March 10, 2003, when it
tripped automatically due to problems with a heater drain tank level control valve and a hotwell
pump. The problems were repaired and the Unit returned to 100 percent power on March 18,
2003. Unit 2 was manually shutdown on March 24, 2003, due to a hydrogen leak on the main
generator. The leak was repaired on March 30, 2003 and the unit was returned to 100 percent
power.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity,
1R01 Adverse Weather Protection
a. Inspection Scope
The inspectors observed the licensee responsed to a tornado watch on March 19, 2003.
The inspectors reviewed licensee Procedure AOP-N.02, Tornado Watch/Warning,
Revision 11, for its effectiveness to limit the risk of tornado-related initiating events and
to adequately protect mitigating systems from the effects of a tornado. In addition, the
inspectors verified the securing of large outside cranes in accordance with guidance in
Topical Report 24370-TR-C-002, Rigging and Heavy Load Handling.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
a. Inspection Scope
The inspectors conducted partial walkdowns of the following three systems to verify the
availability of redundant or diverse systems and components and that defense-in-depth
was maintained during periods when safety equipment was inoperable. The inspectors
reviewed applicable operating procedures, walked down critical system components,
and reviewed identified problems to ensure they were entered into the corrective action
program. Documents reviewed are listed in the attachment.
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- Alternate Emergency Diesel Generator (EDG) during unavailability of EDG 1A-A
- B-train of auxiliary feed water during unavailability of Motor Driven Auxiliary Feed
Water Pump 1A-A
- A-Train electric board room chiller during unavailability of B-train electric board
room chiller
b. Findings
No findings of significance were identified.
1R05 Fire Protection
a. Inspection Scope
The inspectors conducted a tour of eight areas to assess the material condition,
operational status, and lineup of fire protection systems, equipment, and features. The
inspectors assessed control of transient combustibles and ignition sources, and verified
fire protection equipment was available for use. Documents reviewed are listed in the
attachment. The areas toured are listed below.
- Essential Raw Cooling Water Building
- Auxiliary building Elev. 669 (2A-S turbine driven auxiliary feed water pump room)
- Emergency Diesel Generator Building
- Auxiliary building Elev. 653 (1A-A residual heat removal pump room)
- Auxiliary building Elev. 653 (1B-A residual heat removal pump room)
- Turbine Building Elev. 662
- Unit 1 Annulus
- Auxiliary building Elev. 714 (temporary containment access pathway)
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures
a. Inspection Scope
The inspectors reviewed selected risk-important plant design features and licensee
procedures intended to protect the plant and its safety-related equipment from internal
and external flooding events. The inspectors reviewed flood analysis and design
documents including UFSAR Sections 2.3 and 2.4, including Appendix 2.4A, Flood
Protection Plan, and Design Criteria Document SQN-DC-V-12.1, Sequoyah Nuclear
Plant - Flood Protection Provisions, for licensee commitments. The inspectors also
reviewed licensee instructions for cross-tying systems in the event of severe flooding
and evaluated the availability of a selected Unit 1 spool piece identified in the
instructions and on Drawing 1,2-47W845-2, Flow Diagram - Essential Raw Cooling
Water System. The inspectors reviewed selected risk-important external flood
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protection barriers to evaluate the inadequacy at protecting risk-important equipment.
The inspectors performed a walkdown of risk-significant areas, susceptible systems,
and equipment to verify that the respective floor drain system, including room sump
pumps, was operable, including:
- Essential Raw Cooling Water (ERCW) pump house elevations 704' and 720'
- 161-kV cable tunnel
The inspectors reviewed the following plant procedures for coping with flooding events
to verify that the actions were consistent with the plants design basis assumptions:
- AOP-N.03, Revision 16, Flooding
- AOP-N.04, Revision 5, Break of Downstream Dam
The inspectors also reviewed the licensees corrective action documents with respect to
flood-related items identified in Problem Evaluation Reports (PERs) written in 2002 to
verify the adequacy of the corrective actions:
- PER 02-003277-000, AOP-N.04, Break of Downstream Dam, was revised to add
steps to makeup to the forebay using ERCW to maintain the required level.
- PER 02-005674-000, AOP-N.03, Flooding, was revised to re-align the sluice
gates not previously included in the procedure to satisfy the requirements of
Design Criteria SQN-DC-V-12.1, Flood Protection Provisions.
The inspectors also reviewed completed preventive maintenance procedures for
monthly checks for standing water in manholes/handholes for September and
December 2002 and related PER 03-000418-000.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
a. Inspection Scope
The inspectors observed simulator training on February 19, 2003. The scenario
involved a leak on the Residual Heat Removal (RHR) system during mid-loop
operations. The leak was within the capability of the charging system. This placed the
simulated unit in the abnormal operating procedure for RHR malfunctions.
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The inspectors observed crew performance to ensure the following criteria were
satisfied: appropriate communications; ability to take timely and proper actions;
prioritizing, interpreting, and verifying alarms; correct use and implementation of
procedures, including the alarm response procedures; timely control board operation
and manipulation, including high-risk operator actions; oversight and direction provided
by the shift manager, including the ability to identify and implement appropriate
Technical Specification (TS) actions; and group dynamics involved in crew performance.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
a. Inspection Scope
The inspectors reviewed six activities to verify that the appropriate risk assessments
were performed prior to removing equipment for work. When emergent work was
performed, the inspectors verified that the risk for the work was assessed and required
equipment was protected. The inspectors referenced Procedure SPP-7.1, Work
Control Process, Revision 4, and Instruction, 0-TI-DSM-000-007.1, Equipment to Plant
Risk Matrix, Revision 7, during these inspection activities.
- Removal of the 1A-A Emergency Diesel Generator from service for maintenance
- Removal of the Unit 2 Turbine Driven Auxiliary Feed Water Pump from service
for check valve testing
- Loss of Unit 2 Refueling Water Storage Tank (RWST) Instrumentation
- Unavailability of Auxiliary Feed Water level control valve 1-LCV-3-156 following
in-service testing
- Operational Defense-in-Depth Assessment for Week of March 21, 2003
b. Findings
No findings of significance were identified.
1R14 Personnel Performance During Non-Routine Plant Evolutions
a. Inspection Scope
The inspectors reviewed operating crew performance and plant indications associated
with the automatic reactor trip and loss of secondary heat sink that occurred on
March 10, 2003, while Unit 2 was operating at 100 percent power. The review evaluated
what occurred and how operators responded to the event. The inspectors reviewed
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plant operating logs, plant computer information, associated PERs, and conducted
discussions with operations and engineering personnel. The inspectors also reviewed
plant procedures, to determine whether the operators response was in accordance with
those procedures.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed seven selected functional evaluations and related documents
to verify that the licensee had adequately assessed TS operability. In addition, the
inspectors reviewed applicable documents to verify that the system or component was
capable of performing required functions and any required compensatory actions were
properly implemented. The inspectors reviewed the functional evaluations against the
requirements of licensee Procedure SPP-10.6, Engineering Evaluations for Operability
Determination. Additional documents reviewed are listed in the attachment.
- PER 03-000290-000, Inability to reach Mode 5 in 30-hour limit required by TS
during testing
Standard 43
- Breach Permit VBP-2002-0071, Core Drill 4 inch diameter scaffold holes in Unit
- PER 03-001354-000, EDG 2A1 Pillow Block Bearing Alignment
- PER 03-003216-000, High temperature conductor feeding electric board room
chiller B-B
b. Findings
Introduction: In reviewing the operability evaluation and associated aspects of a four-
inch diameter hole drilled in the dome of the Unit 1 Shield Building for the steam
generator replacement outage, the inspectors identified a green NCV for failure to
provide complete instructions governing shield building breaches.
Description: The licensee opened the four-inch diameter shield building breach to allow
workers to pass scaffold material through the dome rather than carry it up the ladder in
the annulus. The licensee further indicated that the breach area had been analyzed and
6
was less than the area that would affect the operability of the Emergency Gas
Treatment System (EGTS) and annulus vacuum systems. The inspectors reviewed the
breach permit for the hole; V.P.-2002-0071; the associated operability evaluation; and
Calculation 65NQL041296, Determine Maximum Breach Area Between Auxiliary
Building Secondary Containment Envelope, Outside, and The Shield Building. The
inspectors noted that the area of the shield building breach was 12.57 square inches
and that the calculation allowed 14 square inches before affecting the operability of the
EGTS System, a margin of less than two square inches.
On February 15, 2003, the licensee initiated Problem Evaluation Report (PER) 03-
001577-000, which identified that two other shield building breaches had not been
documented on Vent Boundary Tracking Sheets. Because this indicated the possibility
of three simultaneous breaches of the shield building, the inspectors reviewed the
tracking sheets, Procedure, 0-TI-SXX-000-016.0, Breaching The Shield Building,
Auxiliary Building Secondary Containment Envelope (ABSCE), or Control Room
Boundaries, Revision 15, and interviewed personnel associated with installation of the
breaches. The inspectors determined that the work documents which installed the
breaches adequately controlled the work such that the amount of shield building area
open at any one time was less than 14 square inches. However, the inspectors
subsequently identified that this control was only successful in this case because all
three breaches were controlled by the same organization, (i.e. the Steam Generator
Replacement Project).
Procedure 0-TI-SXX-000-016.0 controlled breaches via appendices, one for each area,
with instructions for anyone using the procedure to go directly to the applicable
appendix. The inspectors determined that, even though a general precaution specified
a vent boundary log, there were no specific instructions in the appendix for shield
building breaches (Appendix D) that required breaches to be logged or required that the
breached area be added to the log when a permit was approved. Without these
instructions the inspectors concluded that specific breaches could be missed and not
logged as happened with the two breaches in PER 03-001577-000.
Analysis: The inspectors determined that this finding affected only the radiological
barrier function of the containment. If left uncorrected it could result in the actual
breached area exceeding the margin of operablility for the EGTS system, a more
significant safety concern. The finding also affected the configuration control attribute of
the containment barrier. This makes it more than minor. However, because the actual
margin was not exceeded, there was no degradation to the radiological barrier function
of the containment. Therefore, the inspectors considered the finding to be of very low
safety significance (Green).
The inspectors also determined that there was a Problem Identification and Resolution
(PI&R) aspect to this finding. PER 03-001577-000 identified that two shield building
breaches had not been tracked. However, the PER did not identify the lack of specific
instructions nor consider that the undocumented breaches had the potential to allow
enough of the shield building to be breached to exceed the margin of operability for the
EGTS system. The inspectors therefore considered this finding to indicate a potential
problem identification deficiency and have noted it in Section 4OA2.
7
Enforcement: TS 6.8.1.a, requires that activities affecting quality be prescribed and
accomplished using instructions, procedures, or drawings In Accordance With (IAW)
Regulatory Guide 1.33, Revision 2, February 1978. RG 1.33 requires procedures for
performing maintenance that can affect the performance of safety-related equipment.
Contrary to this, Procedure 0-TI-SXX-000-016.0, which was designated quality related
and controlled work on the safety-related containment barrier, did not contain the
instruction steps necessary to ensure that multiple breaches of the shield building would
be adequately controlled. This is a violation of TS 6.8.1.a. Because it is of very low
safety significance and has been entered into the licensees corrective action program
as PER 03-003612-000, this violation is being treated as an NCV, consistent with
Section VI.A of the NRC enforcement policy: NCV 50-327/03-03-01, Inadequate
Instructions for Controlling Shield Building Breaches.
1R16 Operator Workarounds
a. Inspection Scope
The inspectors reviewed operator actions to manually start and load the security diesel
generator while its auto start feature was out of service to determine whether the
functional capability of the diesel was affected. The inspectors specifically considered
whether the workaround affected the operators ability to implement abnormal or
emergency operating procedures. Documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the five post-maintenance tests listed below to verify that
procedures and test activities ensured system operability and functional capability. The
inspectors reviewed the licensees test procedure to verify that the procedure
adequately tested the safety function(s) that may have been affected by the
maintenance activity, that the acceptance criteria in the procedure were consistent with
information in the applicable licensing-basis and/or design-basis documents, and that
the procedure had been properly reviewed and approved. The inspectors also
witnessed the test or reviewed the test data, to verify that test results adequately
demonstrated restoration of the affected safety function(s). Additional documents
reviewed are listed in the attachment.
failed to properly transfer during testing
- 1-PI-EFT-082-002.B, Diesel Generator 1B-B Two (2) Year Electrical Inspection,
Revision 4
8
- 0-SI-EBT-082-238.2, Diesel Generator Battery Quarterly Operability, Revision 8
- WO 03-001019-000, Electric Board Room Chiller Package B-B, Repair leaks,
Recharge, and Retest
- WO 03-002725-000 Repair 1-PSV-068-0340A0, Unit 1 pressurizer power
operated relief valve
b. Findings
No findings of significance were identified.
1R20 Refueling and Outage Activities
a. Inspection Scope
The inspectors reviewed the outage safety plan and contingency plans for the Unit 1
refueling and steam generator replacement outage to confirm that the licensee had
appropriately considered risk, industry experience, and previous site-specific problems
in developing and implementing a plan that assured maintenance of defense-in-depth.
Between March 17, 2003 and April 5, 2003, the inspectors observed portions of the
shutdown and cooldown processes to verify compliance with TS cooldown restrictions
and monitored licensee controls over the outage activities listed below. Documents
reviewed during the inspection are listed in the attachment.
- Licensee configuration management, including daily outage reports, to evaluate
defense-in-depth commensurate with the outage safety plan and compliance
with the applicable TS when taking equipment out of service.
- Licensee implementation of clearance activities to ensure equipment was
appropriately configured to safely support the work or testing.
- Installation and configuration of reactor coolant instruments to provide accurate
indication and an accounting for instrument error.
- Controls over the status and configuration of electrical systems and switchyard to
ensure that TS and outage safety plan requirements were met.
- Decay heat removal processes to verify proper operation and that steam
generators, when relied upon, were a viable means of backup cooling.
- Controls to ensure that outage work was not impacting the ability to operate the
spent fuel pool cooling system during and after core offload.
- Reactor water inventory controls including flow paths, configurations, and
alternative means for inventory addition, and controls to prevent inventory loss.
- Reactivity controls to verify compliance with TS and that activities which could
affect reactivity were reviewed for proper control within the outage risk plan.
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- Containment closure for control of containment penetrations in accordance with
refueling TS, to ensure that containment closure could be achieved during
selected configurations, and to verify maintenance of secondary containment in
accordance with TS.
- Defueling activities for compliance with TS and to verify proper tracking of fuel
assemblies from the core to the spent fuel pool.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors witnessed surveillance tests and/or reviewed test data of six risk-
significant structures, systems and components (SSC) conducted using the surveillance
instructions, listed below, to assess, as appropriate, whether the SSCs met TS
operability requirements, the Updated Final Safety Analysis Report (UFSAR) and
licensee procedure requirements, and to determine if the testing effectively
demonstrated that the SSCs were operationally ready and capable of performing their
intended safety functions.
- 1-SI-SXP-062-201.B, Centrifugal Charging Pump 1B-B Performance Test,
Revision 7*
- SI-90.8, Reactor Trip Instrumentation Monthly Functional Test (SSPS),
Revision 25 (Unit 1 Train B)
- 2-SI-SXP-003-201.S, Turbine Driven Auxiliary Feed Water Pump 2A-S
Performance Test, Revision 13*
- 0-SI-OPS-082-007.W, AC Electrical Power Source Operability Verification,
Revision 6
- 1-SI-OPS-000-002.0, Shift Log, Revision 65
Revision 9
- This procedure included inservice testing requirements.
b. Findings
No findings of significance were identified.
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1R23 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed the temporary modification described in Temporary Alteration
Control Form (TACF) 2-02-0018-063, Unit 2 refueling water storage tank heaters, to
verify that the design was adequate, the modification was properly installed, the
modification did not affect system operability, drawings and procedures were
appropriately updated, and post-modification testing was satisfactorily performed.
Documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
a. Inspection Scope
The inspectors sampled licensee submittals for the PIs listed below for the period
January 1, 2002, through December 31, 2002. To determine the accuracy of the PI
data reported for that period, guidance contained in NEI 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 2, was used to verify the basis for reporting
each indicator.
Cornerstone: Initiating Events
- Unplanned Scrams per 7000 Critical Hours
- Scrams With Loss of Normal Heat Removal
- Unplanned Power Changes per 7000 Critical Hours
The inspectors reviewed selected LERs and portions of the operator logs to verify that
the licensee had accurately identified the number of scrams and unplanned power
changes greater than 20 percent that occurred during the previous four quarters for both
units. The inspectors also reviewed the accuracy of the number of critical hours
reported and the licensees basis for crediting normal heat removal capability for each of
the reported scrams.
b. Findings
No findings of significance were identified.
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4OA2 Identification and Resolution of Problems
Section 1R15 describes a finding for a procedure that did not contain the instructions
necessary to ensure that multiple breaches of the shield building would be adequately
controlled. The licensee had written PER 03-001577-000 and identified that two shield
building breaches had not been tracked. However, the PER did not identify the lack of
specific instructions nor consider that the undocumented breaches had the potential to
allow enough of the Shield building to be breached to exceed the margin of operability
for the EGTS system. The inspectors therefore considered this finding to indicate a
potential problem identification deficiency.
4OA3 Event Follow-up
.1 Frozen RWST Level Instrumentation (NOED 03-6-001)
On January 24, 2003, Unit 2 RWST wide range level transmitters 2-LT-63-50 and 2-LT-
63-52 failed when the impulse lines froze due to a failure of the strip heaters within the
transmitter enclosures. This resulted in the licensee entering TS 3.0.3. The licensee
requested and was granted discretion from enforcement of TS 3.3.2.9.a, which required
three of four channels to be operable. The NRC granted a one-time 48-hour reduction
in the required minimum number of operable channels from three to two to permit the
licensee to repair the transmitters without shutting down the unit.
The licensee agreed to the following compensatory measures during the period the
NOED was in effect: (1) establishment of temporary heat for all RWST wide level
transmitters for both units, (2) the establishment of a fire watch to monitor the additional
temporary heat, (3) briefing of licensed operators on the situation and review of
procedural operation for manual Emergency Core Cooling System (ECCS) switch over
from the RWST to the containment sump, (4) suspension of all work involving the
RWST channels for both units, and (5) increased Unit 1 RWST level monitoring
frequency from every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The inspectors reviewed the cause and compensatory measures to ensure they
matched the licensees oral assertions and were consistent with NRC policy and
guidance. Pending evaluation of the root cause of the problem leading to the request
for enforcement discretion, and any associated enforcement, this issue is identified as
URI 50-328/03-03-02 Frozen RWST Instrumentation (NOED 03-6-001). Documents
reviewed are listed in the attachment.
.2 Containment Purge Valve Leakage (NOED 03-2-004)
On February 27, 2003, Unit 2 containment penetration X-6 purge valves 2-FCV-30-50
and 2FCV-30-51 failed a local leak rate test due to a broken key on the stem of the
inboard valve. The as-found leakage of 29.6 scfm exceeded the TS 3.6.1.9 acceptance
limit of 11.25 scfm (0.05La). The licensee requested and was granted discretion from
enforcement of TS 3.6.1.9 Action b, which required the inoperable valves to be restored
within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The NRC granted an additional 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br /> for the licensee to identify
the source of leakage, repair or replace the valve(s), and to perform verification testing
without shutting down the unit.
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The licensee agreed to the following compensatory measures during the period the
NOED was in effect: (1) one valve in Penetration X-6 would be closed and deactivated
at all times with leak rate monitoring during the maintenance activity, (2) if overall
containment leakage increased to 0.06La the shutdown actions of TS 3.6.1.9.b would be
implemented, (3) the scheduled testing of Diesel Generator 2A-A would be postponed to
outside the NOED repair activity and no component would be removed from service that
would cause the ORAM-Sentinel risk significance to go above the Green level, (4)
containment purge operations would not be allowed for the duration of the valve
maintenance, and (5) the activity of the reactor coolant would be monitored to provide
early detection of an adverse trend.
The inspectors reviewed the cause and compensatory measures to ensure they
matched the licensees oral assertions and were consistent with NRC policy and
guidance. Pending evaluation of the root cause of the problem leading to the request
for enforcement discretion and any associated enforcement, this issue is identified as
URI 50-328/03-03-03 Containment Purge Valve Leakage. Documents reviewed are
listed in the attachment.
.3 Unit 2 Manual Reactor Trip With Loss of Normal Heat Sink
On March 10, 2003, following a Unit 2 manual reactor trip due to the loss of condensate
pressure and one main feed water pump, the inspectors evaluated plant status,
mitigating actions, and the licensees classification of the event, to enable the NRC to
determine an appropriate NRC response. Balance-of-plant problems following the trip
resulted in the operators breaking vacuum and closing main steam isolation valves,
which resulted in a loss of the normal heat sink. The event was reported to the NRC as
event notification39652 and documented in the licensee corrective action program
as PER 03-002313-000. Evaluation of personnel performance is addressed in Section
1R14.
.4 (Closed) Licensee Event Report (LER) 50-328/2002-003-00, Automatic Reactor Trip
Resulting from a Generator Stator Cooling Water High Temperature Caused by a Raw
Cooling Water Valve Failure.
The LER was reviewed by the inspectors and no findings of significance were identified.
The licensee documented the event and failed equipment in PERs 02-006086-000, 02-
006114-000, and 01-005036-000. This event did not constitute a violation of NRC
requirements. This LER is closed.
The licensee included additional information in this LER regarding the delayed insertion
of Rod Control Cluster Assembly (RCCA) L-11 during the trip. This item has been
previously reviewed by the NRC and is the subject of unresolved item (URI) 50-327,
328/02-02-05, Corrective Actions Related to the Apparent Failure of RCCA L-11 to
Properly Insert.
.5 (Closed) LER 50-327/2002-002-00, Automatic Reactor Trip Resulting From a Failure of
a Breaker Causing an Undervoltage Condition on Two Reactor Coolant Pumps and
Failure to Perform a Technical Specification Required Action
13
The LER was reviewed by the inspectors and no findings of significance were identified.
The licensee documented the event and failed equipment in PER 02-008460-000.
In addition to the event described in this report, the licensee identified that offsite power
to both units was affected by the loss of Start Bus 2B. With one source of offsite power
unavailable to Unit 1, TS 3.8.1.1 required that the remaining source be demonstrated
operable within one hour. The licensee determined that this was not done but later
demonstrated that the proper offsite sources were operable. This licensee identified
violation was previously discussed in Inspection Report 50-327,328/02-04 (Section
4OA7). The inspectors review did not identify any new findings. The licensee
documented the problem in PER 02-008493-000. This LER is closed.
.6 (Closed) LER 50-328/2002-004-00, Reactor Trip Resulting From The Loss of a Reactor
Coolant Pump
The LER was reviewed by the inspectors and no findings of significance were identified.
The licensee documented the event failed equipment in PERs 02-015494 and-000 03-
000190-000. This event did not constitute a violation of NRC requirements. This LER is
closed.
4OA5 Other Activities
.1 NRC Temporary Instruction (TI) 2515/150, Reactor Pressure Vessel Head and Vessel
Head Penetration Nozzles (NRC Bulletin 2002-02)
a. Inspection Scope
The inspectors reviewed the Unit 1 bare metal visual examination and susceptibility
calculations performed by the licensee in response to the NRC Order EA-03-009 on
interim inspection requirements for reactor pressure vessel heads dated February 11,
2003. The inspection guidelines were provided in TI 2515/150. Additional documents
are listed in the attachment.
b. Findings and Observations
No findings of significance were identified. Per the documentation requirements of TI
2515/150, the following attributes were observed:
Verification that visual examination was performed by qualified and knowledgeable
personnel
Two teams of three individuals performed the examination of the Unit 1 reactor head.
One team worked the day shift and one team worked the night shift. One individual on
each shift was a licensee Level III Non-Destructive Examination (NDE) qualified to
perform VT-2 inspections. The inspectors reviewed the qualification records and
verified that these individuals were certified as Level III VT-2 inspectors.
14
The other members of each team were vendor employees that operated the remote
video camera equipment. These individuals had performed the same examination on
Unit 2 in the fall of 2002. The inspectors interviewed all of the individuals and noted they
were knowledgeable of the criteria to determine leakage.
Verification that visual examination was performed in accordance with demonstrated
procedures
The inspectors reviewed Procedure N-VT-17, Visual Examination for Leakage of
Pressurized Water Reactor (PWR) Head Penetrations, Revision 2. The inspectors
observed that the examination was done using this procedure. The inspectors verified
by direct observation and in discussions with examination personnel that the approved
acceptance criteria for head leakage were applied in accordance with the procedures.
Verification that the licensee was able to identify, disposition, and resolve deficiencies
The licensees examination plan included a VT-2 examination using a remote crawler
with attached video cameras in the front and rear. In addition, the examination used the
resolution level of a VT-1. The licensee recorded all examinations of the nozzles. Any
suspected leakage observed by the visual examination was noted and reviewed by
materials engineers. The inspectors verified that the examination results for each
nozzle were individually documented.
Verification that the licensee was capable of identifying the Primary Water Stress
Corrosion Cracking (PWSCC) phenomenon described in the bulletin
The inspectors visually observed the Unit 1 reactor head during the licensees
examination; observed the licensee conduct the examination; discussed the examination
with the licensee examiners prior to, during, and following the examination; and verified
the qualifications of the licensee examination personnel. The inspectors concluded that
the licensees visual examination was adequate to identify potential leakage resulting
from PWSCC cracking of reactor head penetrations.
Evaluate condition of the reactor vessel head (debris, insulation, dirt, boron from other
sources, physical layout, viewing obstructions)
The inspectors viewed the condition of the Unit 1 reactor vessel head via remote video
and performed a direct observation of the peripheral portions of the head. There was
some debris around several nozzles (metal shavings, nails, other construction type
debris). Most of the debris was removed with compressed air. Those nozzles where
the debris could not be removed were reviewed by engineering. At four locations the
licensee used a wedge to support the insulation shroud to allow room for the crawler to
reach the upper portions of the head. The inspectors concluded that this was only a
minimal obstruction and that the annulus area of nozzles near the wedge could be
viewed from the entire circumference. The inspectors observed no other significant
items that prevented a thorough visual examination.
15
Evaluate ability for small boron deposits, as described in the bulletin, to be identified and
characterized
The inspectors observed that the reactor head was generally free of any deposits that
would have hindered the visual examination. The licensee observed evidence of boric
acid leakage around Nozzle 3, performed follow-up NDE on this nozzle, and found no
evidence of a leak path. In addition, the licensee characterized six nozzles on the
periphery of the head (Nozzles 53, 64, 65, 72, 73, and 78) as indeterminate due to
either heavy debris or boron deposits. They performed NDE on five of these nozzles
with no indication of a leak path. The licensee did not perform any extra testing on
Nozzle 78, but determined from isotopic analysis that the boron deposits on this nozzle
as well as those on Nozzle 3 came from external leakage on a previous cycle.
Determine extent of material deficiencies (associated with the concerns identified in the
bulletin) which were identified that required repair
The licensee found boron deposits around Nozzle 3 and boron deposits on six nozzles
around the periphery of the head. The licensee performed NDE on these nozzles to
clarify whether or not the deposits were from inside the head. All NDE results were
negative. Additional inspection per Technical Instruction 2515/150 will be performed for
Unit 1 in the next inspection period. This will include a more in-depth review of the
identified indications in the nozzles and if Reactor Coolant System (RCS) pressure
boundary leakage existed. Technical Instruction 2515/150 will remain open pending
completion of the inspection objectives.
Determine any significant items that could impede effective examinations
Other than those minor examples mentioned above, the inspectors observed no
examples of significant items that could impede the visual examination process.
Determine the basis for the temperatures used in the susceptibility ranking calculation
The licensee used 547°F as the head temperature in the calculation. This was based
on the reactor vessel inlet temperature, T-cold, described in the UFSAR, and test data.
In January, 1981, the licensee placed five thermocouples on the Unit 1 head to test
bypass flow modifications and to confirm the existence of enhanced flow in the head.
The test data showed the head temperature to match T-cold. The inspectors reviewed
the UFSAR and the test data. The test data showed that the lowest T-cold measured
was generally higher than the highest head temperature. In cases where the head
temperature exceeded T-cold, the difference was 3°F or less. Based on this data and
the UFSAR T-cold of 544.8°F, the inspectors determined the calculation was
conservative. The inspectors also checked Unit 2, which was operating at full power
and confirmed that T-cold temperature was less than 547°F.
16
.2 Steam Generator Replacement (SGR) Inspection Overview
This inspection report documents completion of inspections required by Inspection
Procedure (IP) 50001, Steam Generator Replacement Inspection, some of which were
completed in accordance with baseline inspection procedures. The table below
identifies and correlates specific IP 50001 inspection requirements examined during this
inspection period with the corresponding sections of this report.
IP 50001 Section of
Section Inspection Scope This Report
02.02.d.2. Controls and plans to minimize any adverse impact on the 1R4, 1R20,
operating unit and common systems 4OA5.4
02.03.e.1. Establishment of operating conditions including defueling, 1R20
RCS draindown, system isolation and safety tagging
02.03.e.2. Implementation of radiation protection controls 4OA5.3
02.03.e.4. Installation, use, and removal of temporary services 1R20,
4OA5.3
.3 SGR Operating Conditions, Radiation Protection Controls, and Temporary Services
a. Inspection Scope
As required by IP 50001 Section 02.03.e, throughout this inspection period, the
inspectors routinely inspected the following activities as they occurred:
- Establishment of operating conditions including defueling, RCS draindown, and
system isolation and safety tagging/blocking.
- Implementation of radiation protection controls.
- Installation, use, and removal of temporary services directly related to steam
generator replacement activities.
b. Findings
No findings of significance were identified.
17
.4 SGR Controls to Minimize Adverse Impact on Operating Unit
a. Inspection Scope
As required by IP 50001 Section 02.02.d.2, the inspectors reviewed plans and
periodically monitored licensee controls to minimize any adverse impact on the
operating unit and common systems. Specific areas reviewed included:
- Modifications to the ABSCE
b. Findings
No findings of significance were identified.
4OA6 Meetings, including Exit
.1 Exit Meeting Summary
On April 9, 2003, the resident inspectors presented the inspection results to Mr. Rick
Purcell and other members of his staff, who acknowledged the findings. The inspectors
confirmed that proprietary information was not provided nor examined during the
inspection.
.2 Annual Assessment Meeting Summary
Subsequent to the end of this inspection period, on April 10, 2003, the NRCs Chief of
Reactor Projects Branch 6 and the Senior Resident Inspector assigned to the
Sequoyah Nuclear Plant met with the Tennessee Valley Authority (TVA) to discuss the
NRCs Reactor Oversight Process (ROP) and the Sequoyah annual assessment of
safety performance for the period of January 1, 2002 - December 31, 2002. The major
topics addressed were: the NRCs assessment program, the results of the Sequoyah
assessment, and NRC security activities. Attendees included Sequoyah site
management, members of site staff, and corporate management.
This meeting was open to the public. The presentation material used for the discussion
is available from the NRCs document system (ADAMS) as accession number
ML031130023. ADAMS is accessible from the NRC Web site at
http://www/nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel:
J. Bajraszewski, Licensing Engineer
T. Carson, Maintenance Manager
H. Cothran, Steam Generator Manager
D. Clift, Acting Maintenance and Modifications Manager
E. Freeman, Operations Manager
J. Gates, Business & Work Performance Manager
C. Kent, Radcon/Chemistry Manager
D. Koehl, Plant Manager
M. Lorek, Assistant Plant Manager
D. Lundy, Site Engineering Manager
R. Purcell, Site Vice President
R. Rogers, Design Manager
P. Salas, Licensing and Industry Affairs Manager
J. Smith, Site Licensing Supervisor
K. Stephens, Security Manager
NRC personnel:
S. Cahill, Chief, Reactor Projects Branch 6
R. Bernard, Region II, Senior Reactor Analyst
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-328/2003-003-02 URI Frozen RWST Instrumentation
(Section 4OA3.1).
50-328/2003-003-03 URI Containment Purge Valve Leakage
(Section 4OA3.2).
Opened and Closed
50-327/2003-003-01 NCV Inadequate Instructions for
Controlling Shield Building Breaches
(Section 1R15 and 4OA2).
Attachment
2
Closed
50-328/2002-003-00 LER Automatic Reactor Trip Resulting
from a Generator Stator Cooling
Water High Temperature Caused by
a Raw Cooling Water Valve Failure
(Section 4OA3.4).
50-327/2002-002-00 LER Automatic Reactor Trip Resulting
From a Failure of a Breaker Causing
an Undervoltage Condition on Two
Reactor Coolant Pumps and Failure
to Perform a Technical Specification
Required Action (Section 4OA3.5).
50-328/2002-004-00 LER Reactor Trip Resulting From the
Loss of a Reactor Coolant Pump
(Section 4OA3.6).
Discussed
50-327, 328/02-02-05 URI Corrective Actions Related to the
Apparent Failure of RCCA L-11 to
Properly Insert (Section 4OA3.4).
LIST OF DOCUMENTS REVIEWED
1R04 Equipment Alignment
1,2-47W803-2, Flow Diagram, Auxiliary Feedwater, Revision 55
1R05 Fire Protection
0-PI-FPU-410-701.Q, Inspection of Fire Doors, Revision 1
0-SI-FPU-410-703.0, Inspection of FPR Required Fire Doors, Revision 2
0-SI-FPU-013-600.0, Fire Detection Panel 0-L-600 Test, Revision 0
0-SI-FPU-013-601.0, Fire Detection Panel 0-L-601 Test, Revision 0
0-SI-EFT-039-237.0, Diesel Generator Building CO2 Fire Protection System (System
39), Revision 16
Transient Combustible Evaluation 2003-0001, Reactor Building Annulus
Fire Protection Impairment Permit FOR 2003A0074, Sprinklers and detection coverage
out of service for U2 Heating and Ventilation Room - Unprotected Security Guard House
FOR 2003A0072, Sprinkler suppression and Detection Out of Service in U2 Heating and
Ventilation Room - Covered Walkway
1R15 Operability Evaluations
0-SI-EBT-082-238.2, Diesel Generator Battery Quarterly Operability, Revision 8
1R16 Operator Work-Arounds
ODM-3.7, Operations Directive Manual - Operator Work-Around Program
WO 03-000284-000, Transfer switch 0-XSW-201-DA for the Security BU Diesel
Generator failed to properly transfer back to normal during 0-PI-OPS-000-677.0 -
Investigate and Repair
1R19 Post-Maintenance Testing
0-PI-OPS-000-677.0, Operability Performance of Security Backup Diesel Generator,
Revision 14
WO 03-000030-000, Electric Board Room Chiller Pkg. B-B Maintenance
2
1R20 Refueling and Other Outage Activities
Outage and Site Scheduling Directive Manual (O&SSDM) 4.0 - Operational Defense-in-
depth Assessment
March 21, 2003, Operational Defense-in-depth Assessment
Tagout 1-TO-2003-0001 per 0-GO-7 section 5.2[8] and 1-SI-OPS-068-001.0
1-SI-OPS-088-006.0, Containment Building Ventilation Isolation (18 Month/100 Hours/7
Days), Revision 12
1-PI-OPS-068-673.D, Daily Requirements for Reduced Inventory/Midloop Operation
0-GO-13, Reactor Coolant System Drain and Fill Operations
0-PI-IXX-068.001.0, Daily Requirements for Reduced Inventory/Midloop
SPP-5.8, Special Nuclear Material Control (fuel assembly transfer forms)
AOP-M.04, Refueling Malfunctions
0-SI-OPS-000-187.0, Containment Inspection
1R23 Temporary Plant Modifications
Drawings 1,2-45N746-2, Revision 5, 1,2-45N799-6, Revision 6, 45N776, Revision 3
UFSAR Section 6.3, Emergency Core Cooling System,
Unit 2 Technical Specification (TS) 3/4.5.5, SQN-2-SI-OPS-002.0, SQN-63-D053-EPM-
MDE-041593
4OA3 Event Follow-up
Frozen RWST Level Instrumentation
January 28, 2003, TVA NOED Request
January 30, 2003, NRC NOED (03-6-001)
Local Leak Rate Test failure on Unit 2 Containment Purge Exhaust Valves
March 4, 2003, TVA NOED Request
March 6, 2003, NRC NOED (03-2-004)
3
4OA5 Other Activities
Temporary Instruction 2515/150
Startup Test SU-8.5.1 - Units 1 & 2, Data Sheet 9, dated January 12, 13, 14, 17, 23, 30,
and 31, 1981