ML040270002
| ML040270002 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 01/26/2004 |
| From: | Cahill S Reactor Projects Region 2 Branch 6 |
| To: | Scalice J Tennessee Valley Authority |
| References | |
| FOIA/PA-2004-0277 IR-03-005 | |
| Download: ML040270002 (28) | |
See also: IR 05000260/2003005
Text
January 26, 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: BROWNS FERRY NUCLEAR PLANT - NRC INTEGRATED INSPECTION
REPORT 05000260/2003005 and 05000296/2003005
Dear Mr. Scalice:
On December 27, 2003, the US Nuclear Regulatory Commission (NRC) completed an
inspection at your operating Browns Ferry Unit 2 and 3 reactor facilities. The enclosed
integrated quarterly inspection report documents the inspection results, which were discussed
on January 16, 2004 with Mr. Ashok Bhatnager and other members of your staff. Results from
our inspection of your Unit 1 Recovery Project are documented in a separate Unit 1 integrated
inspection report.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
This report documents a self-revealing finding of very low safety significance (Green) which was
determined to involve a violation of NRC requirements. However, because of the very low
safety significance and because the finding was entered into your corrective action program,
the NRC is treating the finding as a non-cited violation (NCV) consistent with Section VI.A of the
NRC Enforcement Policy. If you contest any non-cited violation in the enclosed report, you
should provide a response within 30 days of the date of this inspection report, with the basis for
your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington DC 20555-0001; with copies to the Regional Administrator, Region II; the Director,
Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-
0001; and the NRC Resident Inspector at the Browns Ferry Nuclear Plant.
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) 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/
Stephen J. Cahill, Chief
Reactor Projects Branch 6
Division of Reactor Projects
Docket Nos. 50-260, 50-296
Enclosure: NRC Integrated Inspection Report 05000260/2003005 and 05000296/2003005
w/Attachment: Supplemental Information
cc w/encl: (See page 3)
TVA 3
cc w/encl: Chairman
Karl W. Singer Limestone County Commission
Senior Vice President 310 West Washington Street
Nuclear Operations Athens, AL 35611
Tennessee Valley Authority
Electronic Mail Distribution Distribution w/encl: (See page 4)
James E. Maddox, Vice President
Engineering and Technical Services
Tennessee Valley Authority
Electronic Mail Distribution
Ashok S. Bhatnagar
Site Vice President
Browns Ferry Nuclear Plant
Tennessee Valley Authority
Electronic Mail Distribution
General Counsel
Tennessee Valley Authority
Electronic Mail Distribution
Michael J. Fecht, Acting General Manager
Nuclear Assurance
Tennessee Valley Authority
Electronic Mail Distribution
Michael D. Skaggs, Plant Manager
Browns Ferry Nuclear Plant
Tennessee Valley Authority
Electronic Mail Distribution
Mark J. Burzynski, Manager
Nuclear Licensing
Tennessee Valley Authority
Electronic Mail Distribution
Timothy E. Abney, Manager
Licensing and Industry Affairs
Browns Ferry Nuclear Plant
Tennessee Valley Authority
Electronic Mail Distribution
State Health Officer
Alabama Dept. of Public Health
RSA Tower - Administration
Suite 1552
P. O. Box 303017
Montgomery, AL 36130-3017
TVA 4
Distribution w/encl:
K. Jabbour, NRR
L. Slack, RII EICS
RIDSRIDSNRRDIPMLIPB
PUBLIC
OFFICE DRP/RII DRP/RII DRP/RII DRS/RII DRS/RII DRS/RII
SIGNATURE BLH1 EFC RLM2 via email (GTH1) via email (EXL2) via email (DCP)
NAME BHolbrook EChristnot RMonk GHopper ELea DPayne
DATE 01/23/2004 01/23/2004 01/23/2004 01/23/2004 01/26/2004 01/23/2004
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
PUBLIC DOCUMENT YES NO
C:\ORPCheckout\FileNET\ML040270002.wpd
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-260, 50-296
Report No: 50-260/03-05, 50-296/03-05
Licensee: Tennessee Valley Authority (TVA)
Facility: Browns Ferry Nuclear Plant, Units 2 & 3
Location: Corner of Shaw and Nuclear Plant Roads
Athens, AL 35611
Dates: September 28, 2003 - December 27, 2003
Inspectors: B. Holbrook, Senior Resident Inspector
E. Christnot, Resident Inspector
R. Monk, Resident Inspector
G. Hopper, Senior Operations Engineer (Section 1R11.2)
E. Lea, Senior Operations Engineer (Section 1R11.2)
D. Payne, Senior Reactor Inspector, (Section 4OA5)
Approved by: Stephen J. Cahill, Chief
Reactor Project Branch 6
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000260/2003-005, 05000296/2003-005; 9/28/2003 - 12/27/2003; Browns Ferry Nuclear
Plant, Units 2 and 3; Maintenance effectiveness.
The report covered approximately a three-month period of routine inspection by resident
inspectors and senior operations engineers and resolution of a previously unresolved item by a
regional engineering inspector. One Green non-cited violation (NCV) was identified. The
significance of issues is indicated by their color (Green, White, Yellow, Red) using the
Significance Determination Process in Inspection Manual Chapter 0609, Significance
Determination Process (SDP). 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: Initiating Events, Mitigating Systems
Green. Maintenance on Control Rod Drive pump 3A was conducted using an
inadequate maintenance procedure. Work practices were inconsistent with the vendor
manual. Pump seal clearances were improperly set and during the post maintenance
test the pump seal rubbed sufficiently to cause sparking and damage of the new seal.
The inspectors identified a non-cited violation (NCV) (Self-Revealing) of 10 CFR Part
50, Appendix B,Section V, Instructions, Procedures, and Drawings. The finding is
greater than minor in that it affects the mitigating systems cornerstone objective and
degrades the attribute of equipment availability and reliability. The finding is of very low
safety significance based on the operation of the standby pump and all other mitigation
systems were available during the activity. (Section 1R12)
B. Licensee Identified Findings
None
Enclosure
Report Details
Summary of Plant Status
On October 28, 2003 Unit 2 was shutdown for a midcycle outage to repair a steam leak in the
condenser, repair an electro hydraulic fluid leak, and correct component leakage in the drywell.
Unit startup began on November 7, 2003. 100% Rated Thermal Power (RTP) was achieved on
November 10, 2003, and remained there through the end of the inspection period.
On October 25, 2003 Unit 3 reduced power to about 65% RTP to perform power suppression
testing to identify the location of leaking fuel, perform surveillance testing, and complete
scheduled maintenance. Power was returned to 100% RTP on October 28. Power was
reduced to about 70% on November 15, 2003 to repair a cracked weld on the feedwater header
long cycle drain line to the condenser. Temporary repairs were completed and power was
increased to 100% on November 16, 2003. The Unit remained at 100% RTP through the end
of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency
Preparedness
1R01 Adverse Weather Protection (Weather Preparation and Actual Cold Weather
Conditions)
a. Inspection Scope
The inspectors reviewed licensee procedure 0-GOI-200-1, Freeze Protection
Inspections, and reviewed licensee actions to implement the procedure in preparations
for cold weather conditions. The inspectors verified that selected valves and
components listed in the attachments of the procedure were in the position specified by
the procedure. The inspectors reviewed the list of open Problem Evaluation Reports
(PERs) to verify that the licensee was identifying and correcting potential problems
relating to cold weather operations. The inspectors reviewed immediate and planned
corrective actions to verify they were appropriate. In addition, the inspectors reviewed
procedure EPI-0-000-FRZ001, Freeze Protection Program for RHRSW Pump Rooms,
Diesel Generator Building, and the Cooling Tower Pumping Station, to assess
maintenance actions and preparations for cold weather conditions that could affect unit
operation.
On November 25, 2003 while outside temperature was approximately 25 degrees F, the
inspectors completed a walkdown inspection of risk significant systems and components
located in outside areas and buildings that were susceptible to cold weather conditions.
The inspectors observed portable heaters, building openings, and heat tracing light
indications to verify proper operation.
Enclosure
2
The inspectors reviewed recent PERs and discussed cold weather conditions with
operations personnel to assess plant conditions and personnel sensitivity to actual cold
weather conditions. The inspectors conducted a walkdown tour of the main control
rooms to assess system performance and alarm conditions of systems susceptible to
cold weather conditions.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment (Partial and Complete Walkdown)
.1 Partial System Lineup
a. Inspection Scope
The inspectors performed a partial walkdown of three safety systems listed below to
verify redundant or diverse train operability, as required by the plant Technical
Specifications (TS) while the other train of the system was out of service. In some
cases, the system was selected because it would have been considered an
unacceptable combination from a Probabilistic Safety Assessment (PSA) perspective for
the equipment to be removed from service while another train or system was out of
service. The inspectors walkdown was to verify that selected breaker, valve position,
and support equipments were in the correct position for support system operation. The
walkdown was also done to identify any discrepancies that impacted the function of the
system could lead to increased risk.
The inspectors reviewed identified and resolved equipment alignment problems that
could cause initiating events or impact the availability and functional capability of
mitigating systems or barriers. The inspectors observations of equipment and
component alignment for the partial walkdowns were compared to the alignment
specified in system procedures included in the attachment of the report.
- Unit 2 Residual Heat Removal Service Water (RHRSW) system Loop D while
Loop B was out of service for piping replacement
- Unit 2 Control Rod Drive system while Standby Liquid Control was in test
configuration and alignment
- Unit 3 3EA Low Pressure Coolant Injection (LPCI) Motor Generator (MG) set
while 3DN LPCI MG set out for maintenance.
b. Findings
No findings of significance were identified.
Enclosure
3
.2 Complete System Walkdown
a. Inspection Scope
The inspectors reviewed licensee procedures 3-OI-74, Residual Heat Removal,
Attachment 1, Residual Heat Removal System (RHR) System Valve Lineup Checklist,
Attachment 2, RHR System Panel Lineup, and Attachment 3, RHR System Electrical
Lineup, and conducted a complete system walkdown of the Unit 3 RHR Loop I. The
inspectors observed indications in the control room, on local panels and control stations,
and observed accessible equipment in the plant to verify material condition, and proper
alignment for standby operation. The inspectors compared switch and valve positions
observed in the field to the applicable procedure attachment requirements to verify
proper alignment. The inspectors also verified selected component positions against
plant drawing 3-47E811-1, RHR System Flow, and the system procedures to verify
correct alignment. The inspectors reviewed selected PERs and the PER database to
verify the licensee was identifying and correcting system deficiencies. The inspectors
also reviewed the system health report, operator workaround list, and the maintenance
rule reports to assess the overall system condition.
b. Findings
No findings of significance were identified.
1R05 Fire Protection Walkdown
a. Inspection Scope
The inspectors reviewed licensee procedure, SPP-10.10, Control of Transient
Combustibles, and SPP-10.9, Control of Fire Protection Impairments, and conducted a
walkdown of the six fire areas listed below to verify a selected sample of the following:
licensee control of transient combustibles and ignition sources; the material condition of
fire equipment and fire barriers; operational lineup; and operational condition of selected
components. Also, the inspectors verified that those selected fire protection
impairments were identified and controlled in accordance with the procedure SPP-10.9.
In addition, the inspectors reviewed the Site Fire Hazards Analysis and applicable
Pre-fire Plan drawings to verify that the necessary fire fighting equipment, such as fire
extinguishers, hose stations, ladders, and communications equipment, were in place.
The inspectors reviewed a sampling of fire protection-related PERs to verify that the
licensee was identifying and correcting fire protection problems. Pre-fire Plan drawings
and documents reviewed are included in the attachment to the report.
- Fire Area 25, Cable Tunnel
- Fire Area 25, Intake Pumping Structure
- Fire Area 16, Unit 2 Control Building Elevation 617
Enclosure
4
- Fire Area 18, Unit 2 Control Building Elevation 606
- Fire Area 16, Unit 3 Control Building Elevation 606
- Fire Area 16, Unit 1 Control Building Elevation 593
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
.1 Resident Inspector Quarterly Review of Testing and/or Training Activities
a. Inspection Scope
The inspectors observed portions of an operator annual examination on November 5,
2003. The inspectors observed three different job performance measures (JPMs)
performed on the plant control room simulator. The inspectors reviewed licensee
procedures TRN-11.4, Continuing Training for Licensed Personnel, TRN-11.9, Simulator
Exercise Guide Development and Revision, and OPDP-1, Conduct Of Operations, to
verify that the conduct of training, the formality of communication, procedure usage,
alarm response, and control board manipulations were in accordance with the above-
referenced procedures. The inspectors compared actions contained in the JPMs to
operations procedures to verify they matched. The inspectors reviewed the JPMs to
verify they identified operator actions that were critical to safe operation. The inspectors
also assessed instructor interface and control of the examination process. The specific
JPMs observed included the following:
- JPM 50, Primary Containment Venting from Pressure Suppression Chamber
Through FCV-84-19
b. Findings
No findings of significance were identified.
.2 Licensed Operator Requalification (Biennial Review)
a. Inspection Scope
During the week of November 17-21, 2003, the inspectors reviewed documentation,
interviewed licensee personnel, and observed the administration of simulator operating
tests and Job Performance Measures (JPMs) associated with the licensees operator
requalification program. Each of the activities performed by the inspectors was done to
assess the effectiveness of the licensee in implementing requalification requirements
identified in 10 CFR 55, Operators Licenses. Evaluations were also performed to
Enclosure
5
determine if the licensee effectively implemented operator requalification guidelines
established in NUREG-1021, Operator Licensing Examination Standards for Power
Reactors, and Inspection Procedure 71111.11, Licensed Operator Requalification
Program. The inspectors also reviewed and evaluated the licensees simulation facility
for adequacy for use in operator licensing examinations. The inspectors observed three
crews during the performance of the operating tests. Documentation reviewed included
written examinations, JPMs, simulator scenarios, licensee procedures, on-shift records,
licensed operator qualification records, watchstanding and medical records, simulator
modification request records and performance test records, the feedback process, and
remediation plans. The records were inspected against the criteria listed inspection
Procedure 71111.11. Documents reviewed during the inspection are listed in the
Attachment.
Following the completion of the annual operating examination testing cycle which ended
on December 4, 2003, the inspectors reviewed the overall pass/fail results of the
individual JPM operating tests, and the simulator operating tests administered by the
licensee during the operator licensing requalification cycle. These results were
compared to the thresholds established in NRC Manual Chapter 609 Appendix I,
Operator Requalification Human Performance Significance Determination Process.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the two samples listed below for items such as: (1) appropriate
work practices; (2) identifying and addressing common cause failures; (3) scoping in
accordance with 10 CFR 50.65(b) of the maintenance rule; (4) characterizing reliability
issues for performance; (5) trending key parameters for condition monitoring; (6)
charging unavailability for performance; (7) classification and reclassification in
accordance with 10 CFR 50.65(a)(1) or (a)(2); and (8) appropriateness of performance
criteria for SSCs/functions classified as (a)(2) and/or appropriateness and adequacy of
goals and corrective actions for SSCs/functions classified as (a)(1).
- Unit 2 and 3 containment isolation valves experienced several failures. The
failures were documented as part of the licensees corrective action program in
the following PERs, PER 03-006747-000, PER 03-017441-000, PER 03-002719-
000, and PER 03-021813-000.
- Unit 3 Control Rod Drive (CRD) Pump 3A Maintenance
Enclosure
6
b. Findings
Introduction: A self-revealing non-cited violation (NCV) (Green) of 10 CFR app. B was
identified for inadequate procedure guidance during maintenance activities on Control
Rod Drive (CRD) pump 3A.
Discussion: On October 14, 2003, CRD Pump 3A was removed from service for a 40
hour inboard seal replacement outage. Maintenance on CRD pump 3A was conducted
using procedure MCI-0-085-PMP001, Control Rod Drive Hydraulic Pump - Worthington
2 WT-810 Disassembly, Inspection, Rework and Reassembly. Following maintenance,
the licensee conducted a post maintenance test (PMT) on the pump by performing
section 8.1 of procedure, 3-OI-85, Control Rod Drive System. During the PMT, the
pump seal rubbed sufficiently to cause sparking and the pump was immediately
secured. Subsequent investigation revealed that the drive collar was up against the
gland plate. The pump was out of service an additional 131 hours0.00152 days <br />0.0364 hours <br />2.166005e-4 weeks <br />4.98455e-5 months <br /> for seal maintenance
rework. Later, upon return to service, oil leaked from the inboard bearing causing
Operations to classify the pump as emergency use only for an additional four days.
The oil leak was caused by misadjustment of the Trico oil bubbler. The bubbler was
later adjusted and the pump returned to service. During the maintenance and rework
activity the redundant CRD pump, 3B, was operable and in service. In addition, all other
high pressure sources of water makeup were available.
The inspectors reviewed maintenance work orders, procedure MCI-0-085-PMP001, and
observed field work and the post maintenance test. The inspectors observed work
practices that were inconsistent with the vendor manual, such as specifically checking
seal clearances, ensuring the seal was wet and thoroughly vented prior to pump startup.
The inspectors also found that the procedure did not provide any guidance for setting
the proper seal clearance, for initial run-in of the seal, or for adjusting the Trico oil
bubbler.
Analysis: The inspectors referred to MC 0612 and determined that the finding was more
than minor in that it is associated with the Mitigating Systems and Initiating Events
cornerstones and affected the respective objectives of equipment performance and
availability. For the Mitigating Systems aspect, the CRD system is credited as a high
pressure source of inventory makeup under certain operational conditions. Additional
unavailability impacts this makeup source. For the Initiating Events aspect, the
unavailability of both CRD pumps leads to a condition where the Unit 3 Technical
Specifications for operability of CRD accumulators requires an immediate unit scram.
The inspectors referred to MC 0609, Significance Determination Process, and
determined that the finding was of very low safety significance (Green) because the
conditional core damage frequency for this scenario duration was less than1E-6, and
the standby pump was available and in service during the activity. Other high pressure
sources of water makeup were also available. Additionally, operations was aware of the
misadjusted oil bubbler and CRD pump 3A could have been operated in an emergency
situation.
Enclosure
7
Enforcement: 10 CFR 50, Appendix B, Criterion V, Instructions Procedures and
Drawings, Requires, in part, that, activities affecting quality shall be prescribed by
documented instructions, procedures, and drawings, of a type appropriate to the
circumstances and shall be accomplished in accordance with the instructions. Contrary
to this, on October 16, 2003, quality procedure MCI-0-085-PMP001 was fully
implemented and resulted in damage to the seal of quality related CRD pump 3A that
required additional seal replacement. The procedure did not contain guidance
necessary to correctly install a new seal or directions on how to correctly adjust the oil
bubbler. Because this violation is of very low safety significance and has been entered
in the licensees corrective action program under PER 03-0020163-000, this violation is
being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000296/2003005-01, Inadequate Maintenance Procedure for Control Rod Drive
Pump 3A.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
a. Inspection Scope
For the seven risk and emergent work assessments listed below, the inspectors
reviewed licensee actions taken to plan and control the work activities to effectively
manage and minimize risk. The inspectors verified that risk assessments were being
performed as required by 10 CFR 50.65(a)(4). The inspectors reviewed: licensee
procedure SPP-6.1, Work Order Process Initiation; SPP-7.1, Work Control Process; and
0-TI-367, BFN Dual Unit Maintenance, to verify that procedure steps and required
actions were met. Also, the inspectors evaluated the adequacy of the licensees risk
assessments and the implementation of compensatory measures. In addition, the
inspectors conducted a review of scheduled work activities for work week 2352 with
emphasis on risk significant activities for Division I Core Spray and Fast Start Operability
tests for 3A and 3B Diesel generators. These work activities were identified at an
increased risk level (yellow) and was acceptable per the risk assessment.
- 250 V DC main bank battery all intercell readings failed to meet procedure
acceptance criteria, PER 03-022727 (emergent)
03-19297-00, B level PER 03-19298-00 (emergent)
- Units 3: During trouble shooting a leak was discovered in the diaphragm of valve
3-FCV-84-49, drywell or suppression chamber exhaust to SBGT, WO 03-09335-
00 (emergent)
- 3A EHC Pump Pressure Indicator (3-PI-47-62) isolate and replacement, PER 03-
23296 (scheduled)
- Work week 2352, covering planned maintenance activities for December 22
through December 28, 2003 (scheduled)
Enclosure
8
- Units 2 & 3: 3B RHRSW pump motor failed electrical testing during performance
of WO 02-013695-00, motor replaced (emergent)
- Units 2: HPCI pump experienced an unexpected suction source transfer from the
condensate storage tank to the suppression pool during testing WO 03-024812-
00 and PER 03-024777-00 (emergent)
b. Findings
No findings of significance were identified
1R14 Operator Performance During Non-Routine Evolutions and Events
a. Inspection Scope
On October 24 and 25, 2003, the inspectors observed operator performance during
activities to reduce Unit 3 reactor power to approximately 65% RTP to conduct power
suppression testing to identify possible fuel leaks. The inspectors observed the pre-job
brief and compared observed performance to the requirements of procedure ODM 3-3,
Pre-Evolution, Mid-, and End-of-Shift Briefings. The inspectors also reviewed
procedures OSIL-108, Reactivity Management Expectations, to verify that procedure
requirements were met for the power reduction. In addition, the inspectors compared
operator performance to the requirements of procedure 3-GOI-100-12A, Unit Shutdown
From Power Operation to Cold Shutdown and Reductions in Power During Power
Operations.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following five operability evaluations to verify the technical
adequacy of the evaluation and ensure that the licensee had adequately assessed TS
operability. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)
to verify that the system or component remained available to perform its intended
function. In addition, the inspectors reviewed compensatory measures to verify that
the measures worked as stated and the measures were adequately controlled. Where
applicable, the inspectors reviewed licensee procedure SPP-3.1, Corrective Action
Program, Appendix D, Guidelines For Degraded/Non-conforming Condition Evaluation
and Resolution of Degraded/Non-conforming Conditions, to ensure the licensees
evaluation met procedure requirements. The inspectors also reviewed a sampling of
PERs to verify the licensee was identifying and correcting any deficiencies associated
with operability evaluations.
Enclosure
9
- Unit 2 flow control valves 2-FCV-77-15 and 16 due to AK18 relay operation
(PER 03-018092-00)
- Units 2 and 3 control bay habitability zone inleakage due to unqualified duct work
(PER 03-017922-00)
- Units 2 and 3 common station service transformers A and B load tap changer
control power transformers inadequate for their loads (PER 03-018143-00)
- Unit 2 and 3 operability of various HFA relays observed as part of the licensees
ongoing inspection of approximately 1720 relays ( B level PER 03-18287-00)
- Unit 2 operability of 2B RHRSW heat exchanger service water piping, ASME
code class 3 Section XI, for very low wall thickness due to rust and pitting
(PER 03-19298-00)
b. Findings
No findings of significance were identified.
1R16 Operator Work-Around (OWA) Review
a. Inspection Scope
The inspectors reviewed the status of OWAs for Units 2 and 3 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 conducted a detailed review of the selected OWA that
required operators to verify flow of the control room environmental control system within
five hours of initiation due to a possible low flow condition. The OWA was identified at
the highest level priority (1) to expedite corrections. The inspectors also verified that the
OWA had been reviewed in accordance with site procedures and that work orders had
been developed and scheduled for repair. The inspectors also reviewed PER 03-
017922 associated with the OWA to verify that corrective actions had been established
to correct the deficiency. The inspectors compared their observations and licensee
actions to the requirements of Operations Directive Manual 4.11, Operator Work Around
Program and TVAN Standard Department Procedure OPDP-1, Conduct of Operations.
- OWA 0-031-OWA-2003-0111, verify flow of the control room environmental
control system
b. Findings
No findings of significance were identified.
Enclosure
10
1R19 Post-Maintenance Testing (PMT)
a. Inspection Scope
The inspectors evaluated the following five activities by observing testing and/or
reviewing completed documentation to verify that the PMT was adequate to ensure
system operability and functional capability following completion of associated work.
The inspectors reviewed licensee procedure SPP-6.3, Post-Maintenance Testing, to
verify that testing was conducted in accordance with procedure requirements. For
some testing, portions of MMDP-1, Maintenance Management System, were
referenced.
- Unit 2: PMT for MSIV 2-FCV-1-15 following limit switch repairs, Procedure 2-
SR-3.3.1.1.8(5)
000A/03C) following electrical maintenance
- Unit 3: PMT on 3A Control Rod Drive Pump inboard seal replacement per 3-OI-
85, Control Rod Drive System
Lubrication, and Replacement of LPCI MG-Set Couplings and Bearings
b. Findings
No findings of significance were identified.
1R20 Refueling and Outage Activities
.1 Unit 2 mid-cycle outage
a. Inspection Scope
Risk
Prior to the mid-cycle outage scheduled for October 28, 2003 - November 7, 2003, to
repair a steam leak in an extraction piping bellows in the condenser, correct leaking
components in the drywell, and repair an Electro Hydraulic leak, the inspectors reviewed
the Unit 2 mid-cycle Outage Risk Assessment Report, to verify 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.
The inspectors specifically reviewed the contingency plans for two Level Orange risk
conditions for decay heat removal during maintenance associated with Residual Heat
Removal Service Water system to verify that specific equipment protective actions were
identified. The inspectors review was compared to the requirements in licensee
procedure SPP-7.2, Outage Management. During identified high risk significant
conditions due to equipment availability and/or system configurations, inspectors
Enclosure
11
reviewed if contingency measures were identified and incorporated into the overall
outage and response plan. The inspectors walked down systems in the plant, observed
control room panel lineups and discussed posted risk conditions with operations and
outage personnel to assess licensee personnel knowledge of the risk condition and
mitigation strategies.
The inspectors reviewed the licensees root cause of the steam leak in the main steam
extraction piping, attended meetings with a bellows vendor expert, and reviewed the
licensees actions with respect to a manufacturing defect that led to the bellows failure.
The inspectors review assessed the adequacy of corrective actions and maintenance
activities prior to unit restart.
The inspectors attended two Plant Operations Review Committee (PORC) unit restart
meetings to assess licensee actions to review and discuss activities completed during
the outage and unit readiness for restart.
Unit Shutdown
The inspectors observed selected activities and monitored licensee controls over outage
activities listed below to verify that procedural and regulatory requirements were met.
The inspectors compared their observations to licensee procedure SPP-12.1, Conduct
of Operations, and 2-GOI-100-12A, Unit Shutdown from Power Operations to Cold
Shutdown and Reduction in Power During Power Operations, to verify that procedure
requirements were met. Part of the activities observed included the following:
- Unit power reduction with control rods and recirculation system flow
- Manual scram of unit and recovery actions
- Core thermal limit verification
- Reactivity monitoring and control
- Startup, shutdown, and realignment of components and systems
- Realignment and transfer of AC power sources
- TS instrument and system performance verification
The inspectors reviewed licensee procedures 2-OI-74, Residual Heat Removal System
(RHR), and conducted a main control room panel walkdown to verify correct system
alignment. The inspectors reviewed operational logs to verify that procedure and TS
requirements to monitor and record reactor coolant temperatures were met. In addition,
the inspectors reviewed controls implemented to ensure that outage work was not
impacting the ability of operators to operate RHR shutdown cooling.
Enclosure
12
Reactivity Control
The inspectors observed licensee performance during shutdown, outage, and startup
activities to verify that reactivity control was conducted in accordance with procedure
and TS requirements. Inspector observations were compared to procedure SPP-10.4,
Reactivity Management, to verify that procedure and TS requirements were met.
Reactivity manipulations observed included the following:
- Power reduction with control rods and recirculation flow
- Withdrawal of control rods during unit startup
Inspectors also observed the following items to assess licensee performance in the
respective area:
Inventory Control
- Reactor water inventories and controls including flow paths, system
configurations, and alternate means for inventory addition
- Operator monitoring and control of reactor temperature and level
Electrical Power
- Controls over electrical power systems and components to ensure that
emergency power was available as specified in the outage risk report
- Controls and monitoring of electrical power systems and components and work
activities in the power transmission yard
- Operator monitoring of electrical power systems and outages to ensure that TS
requirements were met
Containment Control and Closure
- Confirm secondary containment requirements
- Verify torus and drywell walkdown and closeout prior to unit restart
Preparations and Unit startup
- Unit startup checklist
- Alignment of secondary systems to support startup
- Pre-job briefing for unit startup
- Reactivity management briefing
- Control rod withdrawal for criticality
b. Findings
No findings of significance were identified.
Enclosure
13
1R22 Surveillance Testing
a. Inspection Scope
The inspectors either witnessed portions of surveillance tests or reviewed test data for
the seven risk-significant SSCs listed below, to verify the tests met TS surveillance
requirements, UFSAR commitments, and in-service testing (IST) and licensee
procedure requirements. The inspectors review was to confirm the testing effectively
demonstrated that the SSCs were operationally capable of performing their intended
safety functions. IST data was compared against the requirements of licensee
procedures 0-TI-362, Inservice Testing of Pumps and Valves, and 0-TI-230, Vibration
Monitoring and Diagnostics. The inspectors also reviewed procedures OSIL-108,
Reactivity Management Expectations, and ODM 3-3, Pre-Evolution, Mid-, and
End-of-Shift Briefings, to verify that procedure requirements were met for the
surveillance activities. The surveillances either witnessed or reviewed included:
- 3-SR-3.5.1.1(CS II), Core Spray System Venting Loop II
- 3-SR-3.6.1.3.5 (CS II), Core Spray MOV Operability Test
- 3-SR-3.5.1.6 (CS II), Core Spray Flow Rate Loop II
- 2-SR-3.9.2.2, One-Rod -Out Interlock Functional Test
- 2-SR-3.6.1.3.5 (SD), Valve Cycled During Cold Shutdown, 2-FCV-74-47, and 48
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed licensee procedures 0-TI-405, Plant Modifications and Design
Change Control; 0-TI-410, Design Change Control; SPP-9.5, Temporary Alterations;
and the two temporary modifications listed below to ensure that procedure and
regulatory requirements were met. The inspectors reviewed the associated
10 CFR 50.59 screening against the system design bases documentation to verify that
the modifications had not affected system operability/availability. The inspectors
reviewed selected completed work activities and walked down portions of the systems to
verify that installation was consistent with the modification documents and Temporary
Alteration Control Form (TACF).
- TACF 02-03-007, Revision 0, replace General Electric (GE) neutron monitoring
battery charger B2-2 with a new charger from Stored Energy Systems (SENS)
Enclosure
14
- TACF 02-03-069, Revision 0, replace Unit 2 Regenerative Heat Exchanger 2A
shell-side relief valve, 2-RFV-69-571 with new type of valve
b. Findings
No findings of significance were identified
4. OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
Cornerstones: Mitigating Systems, Initiating Events
.1 Safety System Unavailability - High Pressure Injection System
and Scrams With Loss of Normal Heat Sink
a. Inspection Scope
The inspectors reviewed the licensees procedures and methods for compiling and
reporting PIs, including Procedure SPP-3.4, Performance Indicator for NRC Reactor
Oversight Process, for Compiling and Reporting PIs to the NRC. The inspectors
reviewed raw PI data for the PIs listed below for the fourth quarter 2002 through the
third quarter 2003. The inspectors compared graphical representations, from the most
recent PI report to the raw data to verify that the data was correctly reflected in the
report. The inspectors reviewed licensee procedure SPP 6.6, Maintenance Rule
Performance Indicator Monitoring, Trending and Reporting - 10 CFR 50.65; category A
and B PERs; engineering evaluations and associated PERs; and licensee records to
verify that the PI data was appropriately captured for inclusion into the PI report, and the
PI was calculated correctly. The inspectors reviewed Nuclear Energy Institute (NEI)
99-02, Regulatory Assessment Performance Indicator Guideline, to verify that industry
reporting guidelines were applied.
- Unit 2 Safety System Unavailability - High Pressure Injection
- Unit 3 Safety System Unavailability - High Pressure Injection
- Unit 2 Scrams With Loss of Normal Heat Sink
- Unit 3 Scrams With Loss of Normal Heat Sink
b. Findings
No findings of significance were identified.
Enclosure
15
4OA2 Identification and Resolution of Problems
a. Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems,
and in order to help identify equipment failures or specific human performance issues
for follow-up, the inspectors performed a daily screening of items entered into the
licensees corrective action program. This review was accomplished by a combination
of reviewing hard copies of each condition report, attending daily screening meetings
and accessing the licensees computerized database.
Annual Sample Review
The inspectors selected two PERs for detailed review (PER 03-006967-000 and
00-002340-000). The first PER was associated with the licensees discovery of the
RHRSW discharge flow control valve for RHR heat exchanger 2C stem separated
from the cage; and the second PER dealing with the adequacy of human performance
root cause analysis. The PERs were reviewed to verify that the full extent of the issues
was identified, an appropriate evaluation performed, and appropriate corrective actions
were specified and prioritized. The PERs were evaluated against the requirements of
the licensees CAP as delineated in the Standard Programs and Processes Procedure
SPP-3.1, Corrective Action Program, and 10 CFR 50, Appendix B.
b. Findings and Observations
PER 03-006967-000: There were no identified findings associated with the review of
this sample. The PER was written to evaluate low RHRSW pressure in the 2C RHRSW
subsystem. Hand tightening of valve FCV-23-40, RHRSW discharge flow control valve
for RHR Heat exchanger 2C, indicated valve seat leakage and the PER was revised to
03-006967-001 to disassemble and repair at the first available outage. When the valve
was disassembled during the mid-cycle outage in October, it was found to have its cage
separated from the stem. The inspectors noted, that, though four PERs were written for
emergent difficulties with this valve work, none had a problem description relating
specifically to stem separation. One of the emergent PERs dealt with a problem in
welding activities to weld the valve stem nut to the disc and mentioned that the stem
was separated however, the PER did not specifically focus on the fact that the valve was
found in an unexpected condition, i.e., separated. This was an example of an instance
where a specific PER was not written and the problem description of existing PERs was
incomplete.
PER 00-002340-000: There were no identified findings associated with the review of
this sample. This B Level PER, stated that, in many cases, the human performance root
cause analysis do not get to the fundamental cause of the problem. A search of the
corrective action database revealed that a previous root cause issue was identified in a
1998 PER (98-009421-000). The PER indicated that the analyses of some plant events
did not determine the fundamental reason for human performance deficiencies.
Enclosure
16
The 1998 PER indicated that a sample determined that the root cause analyses for
seven of ten human performance related PERs were weak or inadequate. The root
cause in the PER stated that the inadequacies were caused by failures to follow through
on previously identified corrective actions due to insufficient management oversight.
The inspectors noted that the licensee has now assigned the responsibility for the root
cause analysis (RCA) to the manager of human performance/self-assessment (HP/SA);
expectations for RCAs were that they must include at least one individual who had
attended the RCA training course and the HP/SA manager was to evaluate the need for
refresher training based on RCA quality; develop and pilot a RCA refresher training
course to bring previously trained individuals up to speed on recent changes to the
human performance model, present the refresher training course to all management
review committee(MRC) members, and present the course to personnel identified by
site management to include personnel involved in determination of apparent causes.
The licensee performed an effectiveness review of PER 00-002340-000 and
confirmed that the deficiencies in root causes for human performance did not meet
their expectations. The causal analysis of events triggered by human error continued
to be ineffective in identifying fundamental causes, especially those related to process
and organizational contributors. The inspectors noted that the licensee recently placed
a renewed emphasis on this problem. The inspectors also noted that the root causes
for equipment related problems were generally thorough, detailed, and correct and did
not contain similar root cause deficiencies. This was an example where the
effectiveness of PER corrective actions did not meet licensee managements
expectations.
4OA3 Event Follow-up
Closed: Licensee Event Report (LER) 05000260/2003-005-00: Unplanned Start of DG
A and DG B from Momentary Board Undervoltage
On August 10, 2003, 4KV Shutdown Bus 1 alternate supply breaker failed to
automatically close when the normal supply breaker was manually opened during
electrical switching activities. Operators observed that the alternate supply breaker
failed to close and immediately reclosed the normal supply breaker. As a result, the
shutdown bus lost power for about five seconds. Due to the momentary loss of power
to the shutdown bus, DG A and B automatically started, but did not tie to the bus due
to the short duration of the power loss. Other engineered safety features automatically
started and responded as expected for the loss of power. The licensee determined that
the root cause of the equipment failure was that a connector internal to the breaker had
come off its termination point. The licensee had previously identified that an amber light
on the alternate feeder breaker panel was extinguished and had written an work order
to trouble shoot and repair the problem. However, they failed to realize that the open
circuit that caused the amber light to be extinguished prevented current flow through the
breaker closing coil, thus preventing closure of the alternate supply breaker.
Enclosure
17
The licensee restored equipment to the standby condition, corrected the connection
problem, and initiated long term corrective actions. The LER was reviewed by the
inspectors and no findings of significance were identified. The licensee entered this
problem into the corrective action program as Problem Evaluation Report (PER) 03-
00015160-00.
4A05 Other
(Closed) Unresolved Item (URI) 05000296/2003007-01: Inadequate Unit 3 Fire
Procedure Directs Local Manual Operator Action Be Performed In Location of Fire
During the triennial fire protection inspection (NRC Inspection Report 05000260,
296/2003007, dated November 17, 2003), the inspectors identified a finding having
potential safety significance greater than very low significance, involving procedural
guidance in the Safe Shutdown Instruction (SSI) for Fire Area 13 (Unit 3 480 V RMOV
Board Room 3A) that directed an operator to enter the location of the fire to perform a
local manual action associated with tripping the Unit 3 Reactor Recirculation Pumps
(RRPs). Specifically, Attachment 6, Steps 1.1 and 1.2 of 2/3-SSI-13 directed an
operator to go to 250 V Reactor MOV Board 3A and place the control power breaker
(breaker 1B1) for 4 KV Recirculation Pump Trip (RPT) Board 3-II to off. This action may
not be successful for a severe fire in this room because of the high temperatures, heavy
smoke, low visibility and hazardous plant conditions that would likely be encountered by
the operator while the action is performed. This URI was opened pending further NRC
review of the safety significance of the finding.
The inspectors reviewed licensee calculation ND-Q0999-92116, Appendix R Manual
Action Requirements, Revision 17. This calculation required the RRPs to be tripped
during a severe fire in Fire Area 13 from 4 KV RPT Board 3-II. Additionally, to prevent
potential RRP restart, control power to the RPT board was to be tripped. In general,
RPT control power can be removed by individually opening breaker 1B1 on 250 V
Reactor MOV Board 3A or by totally de-energizing this bus. Normal power to 250 V
Reactor MOV Board 3A is provided from 250 V Battery Board 3 via breaker 203. 250 V
Battery Board 3 is located in different fire area separate from Fire Area 13.
Recognizing that 250 V Reactor MOV Board 3A would be in the location of the fire,
Appendix B, Section Fire Zone/Area 13, of the calculation identified that RPT control
power should be removed by opening breaker 203 in Battery Board Room 3 (to totally
de-energize 250 V Reactor MOV Board 3A.) This requirement was captured in
Attachment 1, Step 1.4.1 of procedure 2/3-SSI-13. Consequently, the operator action at
issue in this URI was redundant and not needed to successfully remove RPT control
power. The licensee initiated a procedure change request (PCR 20031551) to correct
this procedure error.
After reviewing plant operating procedures, operator training and conducting operator
interviews, the inspectors found that several other well known (skill-of-the-craft) methods
were available to the operators for ensuring that the RRPs would be tripped during a
Enclosure
18
severe fire in Fire Area 13. The inspectors concluded that the erroneous procedure
guidance specified in Attachment 6 of 2/3-SSI-13 would have minimal impact on the
operators ability to safely shutdown the Unit 3 reactor. Because this issue has minimal
safety significance and has been documented in the licensees corrective action
program (PER 03-013882-000), this issue is considered to be minor.
URI 05000296/2003007-01 is closed.
4OA6 Management Meetings
Exit Meeting Summary
On January 16, 2004, the resident inspectors presented the inspection results to
Mr. Ashok Bhatnager and other members of his staff, who acknowledged the findings.
The inspectors confirmed that proprietary information reviewed by the inspectors
during the inspection period was returned to the licensee.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
T. Abney, Nuclear Site Licensing & Industry Affairs Manager
A. Bhatnagar, Site Vice President
L. Clardy, Site Nuclear Assurance Manager
C. Ottenfeld, Chemistry Manager
R. Jones, Unit 1 Restart Manager
K. Kruger, Assistant Nuclear Plant Manager
J. Lewis, Nuclear Plant Operations Manager
B. Marks, Engineering & Site Support Manager
B. Mitchell, Radiation Protection Manager
J. Ogle, Site Security
P. Olsen, Maintenance & Modifications Manager
M. Skaggs, Nuclear Plant Manager
T. Golden, Operations Site Licensing Engineer
P. Meek, Operations Site Licensing Engineer
J. Wallace, Operations Site Licensing Engineer
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
None
Closed
05000296/2003005-01 NCV Inadequate Maintenance Procedure for Control
Rod Drive Pump 3A (Section 1R12)
05000260/2003-05 LER Unplanned Start of DG A and DG B from
Momentary Board Undervoltage (Section 4OA3.1)05000296/2003007-01 URI Inadequate Unit 3 Fire Procedure Directs Local
Manual Operator Action Be Performed In Location
of Fire (Section 4A05)
Attachment
2
LIST OF DOCUMENTS REVIEWED
Section 1R04: Equipment Alignment
0-OI-23, Attachment 1B, RHRSW system valve lineup checklist Unit 2
0-OI-23, Attachment 2B, RHRSW system panel lineup checklist Unit 2
2-OI-85, Attachment 1, CRD Hydraulic System Valve Lineup Checklist
2-OI-85, Attachment 2, CRD Hydraulic System Panel Lineup Checklist
2-OI-85, Attachment 3, CRD Hydraulic System Electrical Lineup Checklist
Drawing 3-15E500-3
Section 1R05: Fire Area Tours
Fire Hazards Analysis, Volume 1 and 2
Fire Pre-Plans: IS-550, IS 565, CB2-617, CB3-606, CB2-606
Smoke Detector Locations: Procedure 0-SI-4.11.A.1(3)b
Section 1R11.2: Operator Requalification
BFN-TRN-03-007 Self Assessment Report
Browns Ferry Simulator Transient Test Raw Data
Design Change Request Report
Simulator Problem Report
TRN 11.4 Continuing Training For Licensed Personnel
TRN-11.9 Simulator Exercise Guide Development and Revision
TRN 11.10 Annual Requalification Examination Development and Implementation
TRN -11.12 Job Performance Measures Development Administration and Evaluation Manual
TRN-11.14 TVA Operator Licensing examination Security Program
TRN-12 Simulator Regulatory requirements
OPDP-1 Conduct of Operations
Operation Logs
CAD Records
Reactivation Records
Medical Records
Section 1R20.1: Refueling and Outage Activities
0-OI-57A, Switchyard and 4160 Electrical System
2-SR-3.6.1.2.1, Drywell Airlock LLRT
2-SR-3.6.1.3.5(SD), Valves Cycled During Cold Shutdown
2-SI-3.2.12, Verification Of Fail-Safe Position For MSIVs
2-AOI-100-1. Reactor Scram
2-GOI-100-1A, Unit Startup from Cold Shutdown to Power Operations and Return to Full Power
from Power Reductions
2-GOI-200-2, Drywell Closeout
2-OI-68, Reactor Recirculation System
3
Section 4OA1:Performance Indicator (PI) Verification
Procedures
SPP-3.4, Performance Indicator for NRC Reactor Oversight Process, Rev. 0
Desktop Guide for Identification and Reporting of NEI 99-02, Rev. 2 Performance Indicators
Section 40A5: Other
Procedures
2/3-SSI-13, Unit 3 480 V RMOV Board Room 3A, Rev. 5
Calculations
ND-Q0999-920116, Appendix R Manual Action Requirements, Rev. 17
Procedure Change Requests (PCR) Initiated
PCR 20031551, Delete duplicate action to open RPT Control Power breaker on 250V RMOV
Board 3A, dated 11/18/03