ML103020448
| ML103020448 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 10/29/2010 |
| From: | Eugene Guthrie Reactor Projects Region 2 Branch 6 |
| To: | Krich R Tennessee Valley Authority |
| References | |
| IR-10-004 | |
| Download: ML103020448 (33) | |
See also: IR 05000327/2010004
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
245 PEACHTREE CENTER AVENUE NE, SUITE 1200
ATLANTA, GEORGIA 30303-1257
October 29, 2010
Mr. R. M. Krich
Vice President, Nuclear Licensing
Tennessee Valley Authority
3R Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801
SUBJECT: SEQUOYAH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT
05000327/2010004, 05000328/2010004
Dear Mr. Krich:
On September 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Sequoyah Nuclear Plant, Units 1 and 2. The enclosed inspection report
documents the inspection results discussed on October 7, 2010 with Mr. C. Church and other
members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
This report documents three NRC-identified findings of very low safety significance (Green), all
of which involved violations of NRC requirements. Additionally, a licensee-identified violation
which was determined to be of very low safety significance is listed in this report. However,
because of the very low safety significance and because they are entered into your corrective
action program, the NRC is treating these findings as non-cited violations (NCVs) consistent
with Section 2.3.2 of the NRC Enforcement Policy. If you contest any NCV in this report, you
should provide a response within 30 days of the date of this inspection report, with the basis for
your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk,
Washington DC 20555-0001; with copies to the Regional Administrator, Region II; the Director,
Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-
0001; and the NRC Resident Inspector at Sequoyah Nuclear Plant.
In addition, if you disagree with the characterization of any finding in this report, you should
provide a response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the
Sequoyah Nuclear Plant. The information you provide will be considered in accordance with
Inspection Manual Chapter 0305.
TVA 2
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response (if any) 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 Website at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Eugene F. Guthrie, Chief
Reactor Projects Branch 6
Division of Reactor Projects
Docket Nos.: 50-327, 50-328,72-034
Enclosure: Inspection Report 05000327/2010004, 05000328/2010004
w/Attachment: Supplemental Information
cc w/encl: (See page 3)
_________________________ G SUNSI REVIEW COMPLETE
OFFICE RII:DRP RII:DRP RII:DRP RII:DRP RII:DRP
SIGNATURE Via email Via email Via email CRK /RA/ EFG /RA/
NAME CYoung MSpeck WDeschaine CKontz EGuthrie
DATE 10/28/2010 10/28/2010 10/28/2010 10/29/2010 10/29/2010
E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO
TVA 3
cc w/encl:
C.R. Church
Vice President
Sequoyah Nuclear Plant
Tennessee Valley Authority
P.O. Box 2000
Soddy-Daisy, TN 37384-2000
K. Langdon
Plant Manager
Sequoyah Nuclear Plant
Tennessee Valley Authority
P.O. Box 2000
Soddy Daisy, TN 37384-2000
B. A. Wetzel
Manager
Licensing and Industry Affairs
Sequoyah Nuclear Plant
Tennessee Valley Authority
P.O. Box 2000
Soddy Daisy, TN 37384-2000
E. J. Vigluicci
Assistant General Counsel
Tennessee Valley Authority
6A West Tower
400 West Summit Hill Drive
Knoxville, TN 37902
County Mayor
Hamilton County
Hamilton County Courthouse
Chattanooga, TN 37402-2801
Division of Radiological Health
TN Dept. of Environment & Conservation
401 Church Street
Nashville, TN 37243-1532
Ann Harris
341 Swing Loop
Rockwood, TN 37854
TVA 4
Letter to R. M. Krich from Eugene Guthrie dated October 29, 2010
SUBJECT: SEQUOYAH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT
05000327/2010004, 05000328/2010004
Distribution w/encl:
C. Evans, RII
L. Douglas, RII
OE Mail
RIDSNRRDIRS
PUBLIC
RidsNrrPMSequoyah Resource
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.: 50-327, 50-328
Report Nos.: 05000327/2010004, 05000328/2010004
Licensee: Tennessee Valley Authority (TVA)
Facility: Sequoyah Nuclear Plant, Units 1 and 2
Location: Sequoyah Access Road
Soddy-Daisy, TN 37379
Dates: July 1, 2010 - September 30, 2010
Inspectors: C. Young, Senior Resident Inspector
M. Speck, Resident Inspector
W. Deschaine, Project Engineer (1R05, 1R22)
Approved by: Eugene F. Guthrie, Chief
Reactor Projects Branch 6
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000327/2010004, 05000328/2010004; 07/01/2010 - 09/30/2010; Sequoyah Nuclear Plant,
Units 1 and 2; Heat Sink Performance, Identification and Resolution of Problems, and Event
Followup.
The report covered a three-month period of inspection by resident inspectors and announced
inspections by regional inspectors. Three Green findings were identified. The significance of
most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual
Chapter (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 NRC's program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.
A. NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green. The inspectors identified a non-cited violation of 10 CFR 50 Appendix B
Criterion V, Instructions, Procedures, and Drawings, for the failure to provide
adequate documented instructions for inspection of the containment spray heat
exchangers. Preventive maintenance (PM) procedures associated with these
inspections failed to provide for an adequate inspection of the ERCW side (shell
side) of these heat exchangers. Consequently, the heat transfer capability of these
heat exchangers has not been periodically verified through either testing or
adequate visual inspection. The licensee entered this issue into their corrective
action program as PER 236318. Planned corrective actions include the
development and implementation of a single-tube method for thermal performance
testing of the heat exchangers in lieu of inspection.
The finding was determined to be greater than minor because it was associated
with the equipment performance attribute of the mitigating systems cornerstone and
affected the cornerstone objective to ensure the availability, reliability, and capability
of systems that respond to initiating events to prevent undesirable consequences,
since the heat transfer capability of these heat exchangers has not been periodically
verified through either testing or adequate visual inspection. Using IMC 0609,
Significance Determination Process, Attachment 4, Phase 1 - Initial Screening
and Characterization of Findings, the finding was determined to be of very low
safety significance (Green) since the finding did not represent an actual loss of
safety function. The cause of this finding was determined to have a cross-cutting
aspect of Corrective Action Program Issue Identification in the area of Problem
Identification and Resolution associated with the Corrective Action Program
component, in that the evaluation of PERs in 2009 on the subject of CS heat
exchanger inspection failed to identify the need to resolve the discrepancy between
the scope of the program PMs and the implementing procedure requirement for CS
heat exchanger shell side inspection. Thus, the licensee failed to completely and
accurately identify issues in the corrective action program P.1(a). (Section 1R07)
Enclosure
3
- Green. The inspectors identified a Green non-cited violation of 10 CFR 50
Appendix B Criterion III, Design Control, for the failure to provide design control
measures for verifying the adequacy of the design calculation used to establish the
maximum RHR operating temperature limit for maintaining ECCS operability. A
design calculation yielded a non-conservative temperature limit for use in plant
operations procedures. This resulted in several occasions where ECCS operability
was in question due to the fluid temperature in the RHR system suction piping. The
licensee entered this issue into their corrective action program as PER 215434.
Corrective actions included revising operations procedures to reflect the corrected
temperature limit from a revised calculation.
The finding was determined to be greater than minor because it was similar to
example 3.j. of IMC 0612 Appendix E in that the non-conservatism in the calculation
resulted in a condition where reasonable doubt existed as to the operability of the
ECCS system. Additionally, it was associated with the procedure quality attribute of
the mitigating systems cornerstone and affected the cornerstone objective to ensure
the availability, reliability, and capability of systems that respond to initiating events
to prevent undesirable consequences. Specifically, plant procedures for RHR
system operation contained non-conservative temperature limits for ensuring TS
operability, and actual system temperatures exceeded the revised appropriate limit
on several occasions. Using IMC 0609, Significance Determination Process,
Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the
finding was determined to be of very low safety significance (Green) since the
finding did not represent an actual loss of safety function. No cross-cutting aspect
was identified since the issue was not reflective of current licensee performance,
since the previous calculation in question was last revised and approved in 1996.
(Section 4OA2.3)
Cornerstone: Barrier Integrity
- Green. The inspectors identified a Green non-cited violation of Unit 2 TS 6.8,
Procedures and Programs, for the failure to take prompt action to maintain reactor
thermal power less than the licensed power limit of 3455 megawatts thermal (MWt)
in response to a transient caused by the loss of a condensate booster pump, as
required by station procedures. The licensee entered this issue into their corrective
action program as PER 259098. The licensee is currently evaluating for planned
corrective actions.
The finding was determined to be greater than minor because it was similar to
example 8.b. of IMC 0612 Appendix E. Additionally, it was associated with the
Human Performance attribute of the Barrier Integrity cornerstone and affected the
cornerstone objective relative to the fuel cladding barrier since operation above the
licensed power limit reduces analyzed margins to fuel cladding damage. Using IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial
Screening and Characterization of Findings, the finding was determined to be of
very low safety significance (Green) since only the fuel cladding barrier was
affected. The cause of this finding was determined to have a cross-cutting aspect
of Conservative Assumptions and Safe Actions in the area of Human Performance
Enclosure
4
associated with the Decision Making component. The decision to take no operator
action in response to the thermal power transient reflected a non-conservative
assumption that average thermal power could be allowed to exceed the licensed
limit without operator action while the feedwater control system responded to the
transient associated with the condensate pump failure H.1(b). (Section 4OA3.3)
Enclosure
REPORT DETAILS
Summary of Plant Status:
Unit 1 operated at or near 100 percent rated thermal power (RTP) for the entire inspection
period.
Unit 2 operated at or near 100 percent RTP until September 28, 2010, when power was
reduced to approximately 84 percent RTP in response to the loss of one condensate booster
pump. Unit 2 remained at 84 percent RTP while conducting repairs for the remainder of the
inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04 Equipment Alignment
Partial System Walkdown
a. Inspection Scope
The inspectors performed four partial walkdowns of the following systems to verify the
operability of redundant or diverse trains and components when safety equipment was
inoperable. The inspectors focused on identification of discrepancies that could impact
the function of the system and, therefore, potentially increase risk. The inspectors
reviewed applicable operating procedures, walked down control system components,
and determined whether selected breakers, valves, and support equipment were in the
correct position to support system operation. The inspectors also verified that the
licensee had properly identified and resolved equipment alignment problems that could
cause initiating events or impact the capability of mitigating systems or barriers and
entered them into the corrective action program (CAP). Documents reviewed are listed
in the Attachment.
- Unit 1 Auxiliary Feedwater Motor-driven A-train and B-train During Turbine-driven
train Unplanned Maintenance
- Emergency Diesel Generators 1A-A, 2A-A, 2B-B During 1B-B Planned Maintenance
- Unit 1 Containment Spray System Train B During Train A Maintenance
- Unit 1 Emergency Core Cooling System Train A During Emergent Train B
Maintenance
b. Findings
No findings were identified.
Enclosure
6
1R05 Fire Protection
.1 Fire Protection Tours
a. Inspection Scope
The inspectors conducted a tour of the six areas important to safety listed below to
assess the material condition and operational status of fire protection features. The
inspectors evaluated whether: combustibles and ignition sources were controlled in
accordance with the licensees administrative procedures; fire detection and suppression
equipment was available for use; passive fire barriers were maintained in good material
condition; and compensatory measures for out-of-service, degraded, or inoperable fire
protection equipment were implemented in accordance with the licensees fire plan.
Documents reviewed are listed in the Attachment.
- Emergency Diesel Generator Building
- Control Building Elevation 706 (Cable Spreading Room)
- Control Building Elevation 685 (Auxiliary Instrument Rooms)
- Control Building Elevation 669 (Mechanical Equipment Room, 250 VDC Battery and
Battery Board Rooms)
- Auxiliary Building Elevation 690 (Corridor)
- Auxiliary Building Elevation 714 (Corridor)
b. Findings
No findings were identified.
.2 Annual Drill Observations
a. Inspection Scope
On July 21, 2010, the inspectors observed an unannounced fire drill in the Diesel
Generator Building Board Room 1A-A. The inspectors assessed fire alarm
effectiveness; response time for notifying and assembling the fire brigade; the selection,
placement, and use of firefighting equipment; use of personnel fire protective clothing
and equipment (e.g., turnout gear, self-contained breathing apparatus); communications;
incident command and control; teamwork; and fire fighting strategies. The inspectors
also attended the post-drill critique to assess the licensees ability to review fire brigade
performance and identify areas for improvement. Following the critique, the inspectors
compared their findings with the licensees observations and to the requirements
specified in the licensees Fire Protection report. This activity constituted one inspection
sample.
b. Findings
No findings were identified.
Enclosure
7
1R06 Flood Protection Measures
a. Inspection Scope
The inspectors reviewed one internal flood protection measures sample for the Turbine
Building/Control Building interface flood barriers to verify that structures and penetrations
were consistent with the drawings and design requirements and risk analysis
assumptions and that equipment essential for reactor shutdown was properly protected
from a flood caused by pipe breaks in the turbine building. Specifically, the inspectors
reviewed the licensees drawings and walked down the barriers separating the turbine
and control buildings to verify the adequacy of common area drainage, flood detection
instrumentation, and that physical barriers were intact to ensure that a flooding event
would not impact reactor shutdown capabilities. Documents reviewed are listed in the
Attachment. The inspectors completed one sample.
b. Findings
No findings were identified.
1R07 Heat Sink Performance
a. Inspection Scope
The inspectors reviewed the licensees execution and on-line monitoring of biofouling
controls to verify whether the licensee had developed acceptance criteria for these
controls. Specifically, the inspectors reviewed SPP-9.7, Corrosion Control Program,
Revision 17, interviewed chemistry and engineering personnel, and reviewed chemistry
implementing procedures to ensure that SPP-9.7 requirements were implemented. The
inspectors also reviewed the licensees Generic Letter (GL) 89-13 commitments relating
to safety-related heat exchangers cooled by raw service water. The inspectors observed
the inspection of the shell side (raw water side) of the 1B containment spray heat
exchanger as well as documentation of the inspection of the 1A, 2A, and 2B containment
spray heat exchangers in accordance with the licensees Generic Letter 89-13 Program.
Documents reviewed are listed in the Attachment. The inspectors completed one
sample.
b. Findings
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50
Appendix B Criterion V, Instructions, Procedures, and Drawings, for the failure to
provide adequate documented instructions for inspection of the containment spray heat
exchangers. Preventive maintenance (PM) procedures associated with these
inspections failed to provide for an adequate inspection of the ERCW side (shell side) of
these heat exchangers. Consequently, the heat transfer capability of these heat
exchangers has not been periodically verified through either testing or adequate visual
inspection.
Enclosure
8
Description. On July 18, 1989, the NRC issued Generic Letter (GL) 89-13 Service
Water System Problems Affecting Safety-Related Equipment which requested licensees
to implement a program including testing and/or inspection in order to ensure adequate
heat transfer capability of applicable safety-related heat exchangers which use raw
service water for cooling. The licensees equivalent safety-related raw service water
system is the Essential Raw Cooling Water (ERCW) system. On September 22, 1995,
the licensee submitted a revised GL 89-13 program response which indicated that, for
the containment spray (CS) heat exchangers, periodic maintenance and inspection is
performed on the shell side (ERCW) for MIC, clams and mussels, silt, biofouling, and
corrosion products.
The inspectors reviewed licensee procedure 0-TI-SXX-000-146.0, Program For
Implementing NRC Generic Letter 89-13, revision 3, which required that visual
inspections of the ERCW side of the CS heat exchangers be performed via the
Preventive Maintenance (PM) Program. Specifically, PM procedures 041461000,
041481000, 041472000, and 041492000 were identified as implementing procedures for
the inspections of CS heat exchangers 1A, 1B, 2A, and 2B, respectively. In January and
March 2010, the inspectors observed the licensees performance of these PM activities.
The inspectors noted that the scope of these PMs was limited to inspection of the interior
of the ERCW inlet pipe to each heat exchanger, and that the location of the inspection
precluded observation of the condition of the shell side of the heat exchanger. The
inspectors concluded that this activity was not adequate to meet the program
requirement for heat exchanger testing/maintenance. The licensee entered this issue
into their corrective action program as PER 236318.
The inspectors also reviewed PER 165626, which documented that in March 2009, a
licensee self-assessment identified that PMs 041461000, 041481000, 041472000, and
041492000 had not been performed for greater than 5 years. This PER also identified
an action to evaluate the possibility of performing visual inspection on the shell side of
these heat exchangers. In response, the licensee evaluated the possibility of performing
boroscope inspection on the shell side, and concluded that this inspection method would
not be practicable.
The inspectors also reviewed PER 177214, dated July 2009, which was issued as a
follow-up to the above PER 165626 and identified the need to perform a functional
evaluation (FE) to assess the current operability of the CS heat exchangers and
evaluate whether the design basis required heat transfer capability was being
maintained in light of the fact that thermal performance testing and shell side inspections
were not being performed. The inspectors reviewed this FE and concluded that
reasonable assurance exists that these heat exchangers remain capable of performing
their required function based on the results of visual inspections and testing of other raw
water heat exchangers in the plant versus the allowable fouling factors associated with
the CS heat exchangers.
The inspectors were informed by the licensee that planned corrective actions include the
development and implementation of a single-tube method for thermal performance
testing of the heat exchangers in lieu of inspection.
Enclosure
9
Analysis. The licensees failure to provide adequate instructions for inspections of the
containment spray heat exchangers was a performance deficiency. The finding was
determined to be greater than minor because it was associated with the Equipment
Performance attribute of the Mitigating Systems cornerstone and affected the
cornerstone objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences, since the heat transfer
capability of these heat exchangers has not been periodically verified through either
testing or adequate visual inspection. Using IMC 0609, Significance Determination
Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings,
the finding was determined to be of very low safety significance (Green) since the finding
did not represent an actual loss of safety function.
The cause of this finding was determined to have a cross-cutting aspect of Corrective
Action Program Issue Identification in the area of Problem Identification and Resolution
associated with the Corrective Action Program component, in that the evaluation of
PERs in 2009 on the subject of CS heat exchanger inspection failed to identify the need
to resolve the discrepancy between the scope of the program PMs and the implementing
procedure requirement for CS heat exchanger shell side inspection. Thus, the licensee
failed to completely and accurately identify issues in the corrective action program
Enforcement. 10 CFR 50 Appendix B, Criterion V, required that activities affecting
quality shall be prescribed by documented instructions of a type appropriate to the
circumstances, and that instructions shall include appropriate qualitative acceptance
criteria for determining that important activities have been satisfactorily accomplished.
Procedure 0-TI-SXX-000-146.0, Program For Implementing NRC Generic Letter 89-13,
revision 3, required that visual inspections of the ERCW side of the containment spray
heat exchangers be performed via the Preventive Maintenance (PM) Program. Contrary
to this, on January 13, 2010, January 21, 2010, February 25, 2010, and March 11, 2010,
the licensee failed to provide adequate documented instructions which included
appropriate qualitative acceptance criteria for determining that activities affecting quality
have been satisfactorily accomplished. Specifically, instructions provided in PM
procedures 041461000, 041481000, 041472000, and 041492000 were not adequate to
perform the inspections of the ERCW side of the containment spray heat exchangers
identified in 0-TI-SXX-000-146.0. Consequently, the heat transfer capability of these
heat exchangers had not been periodically verified through either testing or adequate
visual inspection. Because this violation was determined to be of very low safety
significance and has been entered into the licensees corrective action program as PER
236318, it is being treated as an NCV consistent with Section 2.3.2 of the NRC
Enforcement Policy: NCV 05000327,328/2010004-01, Inadequate Inspection of Raw
Water Side of Containment Spray Heat Exchangers.
1R11 Licensed Operator Requalification Program
a. Inspection Scope
The inspectors performed one licensed operator requalification program review. The
inspectors observed a simulator session on August 10, 2010. The training scenario
Enclosure
10
involved a reactor coolant system leak followed by a failure of the containment spray
system. Additional anomalies included a containment air return fan failure. The
inspectors observed crew performance in terms of: 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 shift manager, including the ability to identify and implement
appropriate Technical Specification (TS) action; and, group dynamics involved in crew
performance. The inspectors also observed the evaluators critique and reviewed
simulator fidelity to verify that it matched actual plant response. Documents reviewed
are listed in the Attachment. This activity constituted one inspection sample.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the maintenance activity listed below to verify the effectiveness
of the activities in terms of: appropriate work practices; identifying and addressing
common cause failures; scoping in accordance with 10 CFR 50.65 (b); characterizing
reliability issues for performance; trending key parameters for condition monitoring;
charging unavailability for performance; classification in accordance with 10 CFR
50.65(a)(1) or (a)(2); appropriateness of performance criteria for structure, system, or
components (SSCs) and functions classified as (a)(2); and, appropriateness of goals
and corrective actions for SSCs and functions classified as (a)(1). Documents reviewed
are listed in the Attachment.
- System 333 - Auxiliary Feedwater
- PER 241570 - Sampling System Containment Isolation Valve Failures
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the four following activities to determine whether appropriate
risk assessments were performed prior to removing equipment from service for
maintenance. The inspectors evaluated whether risk assessments were performed as
required by 10 CFR 50.65 (a)( 4), and were accurate and complete. When emergent
work was performed, the inspectors reviewed whether plant risk was promptly
reassessed and managed. The inspectors also assessed whether the licensees risk
assessment tool use and risk categories were in accordance with Standard Programs
Enclosure
11
and Processes Procedure (SPP)-7.1, On-Line Work Management, Revision 12, and
Instruction 0-TI-DSM-000-007.1, Risk Assessment Guidelines, Revision 8. Documents
reviewed are listed in the Attachment. This inspection satisfied four inspection samples
for Maintenance Risk Assessment and Emergent Work Control.
unscheduled maintenance
- August 3, 2010, Heavy/complex lift in vicinity of U1/U2 6.9kV Unit Boards and
Condensate Demineralizer Piping
- August 26, 2010, Unplanned Unavailability of Centrifugal Charging Pump 1B
- September 30, 2010, Unit 1 start bus maintenance risk assessment
b. Findings
No findings were identified.
1R15 Operability Evaluations
a. Inspection Scope
For the nine operability evaluations described in the PERs listed below, the inspectors
evaluated the technical adequacy of the evaluations to ensure that TS operability was
properly justified and the subject component or system remained available, such that no
unrecognized increase in risk occurred. The inspectors compared the operability
evaluations to UFSAR descriptions to determine if the system or components intended
function(s) were adversely impacted. In addition, the inspectors reviewed compensatory
measures implemented to determine whether the compensatory measures worked as
stated and the measures were adequately controlled. The inspectors also reviewed a
sampling of PERs to assess whether the licensee was identifying and correcting any
deficiencies associated with operability evaluations. Documents reviewed are listed in
the Attachment.
- PER 237441, EDG/ERCW cable splice submergence performance under flood
conditions
- PER 234171, EGTS Cooldown Valve Failure
- PER 208228, Battery Powered Light Failed Battery Test and Not Corrected Within 14
day Allowed Outage Time
- PER 232000, ERCW Missile Shield Concrete Test Values Outside of Acceptance
Range
- PER 246077, 1B Centrifugal Charging Pump Mechanical Seal Leakage
- SR 243845, Vital Battery V Discharge Test Procedure Not Followed
- PERs 238372 and 238550, Unit 1 Turbine driven auxiliary feedwater pump suction
pressure switch logic relay and flow controller failure
- PER 236305, Scaffold secured to containment spray heat exchanger drain line
- SR 252775, RWST aligned to non-safety related system on recirculation
Enclosure
12
b. Findings
No findings were identified.
1R18 Plant Modifications
a. Inspection Scope
The inspectors reviewed the temporary modification listed below and the associated 10
CFR 50.59 screening, and compared it against the UFSAR and TS to verify whether the
modification affected operability or availability of the affected system.
- TACF 0-10-0011-082, Install Diesel Generator Fuel Tank Atmospheric Vent Screens
Following installation and testing, the inspectors observed indications affected by the
modification, discussed them with operators, and verified that the modification was
installed properly and its operation did not adversely affect safety system functions.
Documents reviewed are listed in the Attachment. The inspectors completed one
sample.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the five post-maintenance tests associated with the work orders
(WOs) listed below to assess whether procedures and test activities ensured system
operability and functional capability. The inspectors reviewed the licensees test
procedure to evaluate whether: the procedure adequately tested the safety function(s)
that may have been affected by the maintenance activity; the acceptance criteria in the
procedure were consistent with information in the applicable licensing basis and/or
design basis documents; and the procedure had been properly reviewed and approved.
The inspectors also witnessed the test or reviewed the test data to determine whether
test results adequately demonstrated restoration of the affected safety function(s).
Documents reviewed are listed in the Attachment.
- WO 111061334, Repair EGTS B-train Cooldown Valve Function
- WO 111138619, Unit 1 Turbine-driven AFW Pump Time Delay Relay (TD-2)
Replacement
- WO 111143594, Unit 1 Turbine-driven AFW Pump Flow Controller Replacement
Enclosure
13
- WO 110835968, Inspect, Clean, and Tighten 2B Diesel Generator Battery
Connection
- WO 11325613, Evaluate and Repair 1B Centrifugal Charging Pump Mechanical Seal
Leakage
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
For the four surveillance tests identified below, the inspectors assessed whether the
SSCs involved in these tests satisfied the requirements described in the TS surveillance
requirements, the UFSAR, applicable licensee procedures, and whether the tests
demonstrated that the SSCs were capable of performing their intended safety functions.
This was accomplished by witnessing testing and/or reviewing the test data. Documents
reviewed are listed in the Attachment. The inspectors completed four samples.
Routine Surveillance Tests:
- 0-SI-NUC-000-007.0, Measurement of the At-Power Moderator Temperature
Coefficient, Revision 16
- 0-SI-EBT-082-238.2, Diesel Generator Battery Quarterly Operability, Revision 18
- 2-SI-IFT-099-90.8B, Reactor Trip Instrumentation Monthly Functional Test (SSPS)
Train B, Revision 17
In-Service Tests:
- 1-SI-SXP-063-201.B, Safety Injection Pump 1B-B Performance Test, Revision 13
b. Findings
No findings were identified.
1EP6 Drill Evaluation
a. Inspection Scope
Resident inspectors evaluated the conduct of a routine licensee emergency drill on
September 1, 2010 to identify any weaknesses and deficiencies in classification,
notification, and protective action recommendation (PAR) development activities. The
inspectors observed emergency response operations in the simulated control room to
verify that event classification and notifications were done in accordance with EPIP-1,
Emergency Plan Classification Matrix, Revision 43. The inspectors also attended the
licensee critique of the drill to compare any inspector-observed weakness with those
Enclosure
14
identified by the licensee in order to verify whether the licensee was properly identifying
deficiencies. The inspectors completed one sample.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
4OA2 Identification and Resolution of Problems
.1 Daily Review
a. Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems,
and in order to help identify repetitive equipment failures or specific human performance
issues for follow-up, the inspectors performed a daily screening of items entered into the
licensees CAP. This was accomplished by reviewing the description of each new PER
and attending daily management review committee meetings.
b. Findings and Observations
No findings were identified.
.2 Selected Issue Follow-up: Maintenance Rule scoping of SSCs used in EOPs
a. Inspection Scope
In August 2008, the NRC issued a Green NCV of 10 CFR 50.65(b)(2)(i) for the failure to
include a component within the scope of the maintenance rule monitoring program on
the basis that the use of the component was prescribed in emergency operating
procedures (EOPs) (this was issued in IR 05000327,328/2008003). The licensee issued
PER 142050 in response to this identified violation. In August 2009, the NRC identified
that the licensee had not taken action to determine the extent of additional components
not being monitored within the maintenance rule program which would fall under the
same scoping criteria. The NRC opened Unresolved Item (URI)
05000327,328/2009006-02, Inadequate Scoping of SSCs Used in EOPs into the
Maintenance Rule Program, in IR 05000327,328/2009006 to determine whether
additional scoping violations existed based on the licensees evaluation to be conducted.
The licensee issued PER 177211 to address this issue. The inspectors reviewed the
licensees actions, which included chartering a comprehensive evaluation study to
identify plant components used in EOPs and evaluate each for scoping into the
maintenance rule monitoring program. This effort is ongoing as of the time of this
inspection report.
Enclosure
15
b. Findings and Observations
No findings were identified. The inspectors have reviewed the scope and status of the
ongoing evaluation and determined that the licensee is taking appropriate action to
address the issue. To date, the licensee has scoped into the maintenance rule
monitoring program the steam dump valves, which were identified by the NRC as not
being previously scoped. It is not expected that any additional previously unscoped
components which may be identified as a result of this evaluation would constitute
violations of 10 CFR 50.65(b)(2)(i) of more than minor significance.
.3 Selected Issue Follow-up: Potential for RHR system suction line voiding when aligned
for ECCS injection
a. Inspection Scope
The inspectors reviewed the licensees actions to address the potential for voiding in the
RHR system suction piping whenever the fluid temperature exceeds the saturation
temperature associated with ECCS injection alignment. The inspectors reviewed the
licensees evaluation of Westinghouse Nuclear Safety Advisory Letter (NSAL) 09-8,
Presence of Vapor in Emergency Core Cooling System/Residual Heat Removal System
in Modes 3/4 Loss-of-Coolant Accident Conditions, which was issued in November
2009. The licensee issued PERs 203852 and 155933 to evaluate the concern. The
inspectors also reviewed NRC Information Notice (IN) 2010-11, Potential For Steam
Voiding Causing Residual Heat Removal System Inoperability, and verified that the
licensee had incorporated a review of this IN in their evaluation.
b. Findings and Observations
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50
Appendix B Criterion III, Design Control, for the failure to provide design control
measures for verifying the adequacy of the design calculation used to establish the
maximum RHR operating temperature limit for maintaining ECCS operability. A design
calculation yielded a non-conservative temperature limit for use in plant operations
procedures. This resulted in several occasions where ECCS operability was in question
due to the fluid temperature exceeding temperature limits in the RHR system suction
piping.
Description. The inspectors reviewed the licensees evaluation of Westinghouse
Nuclear Safety Advisory Letter (NSAL) 09-8, Presence of Vapor in Emergency Core
Cooling System/Residual Heat Removal System in Modes 3/4 Loss-of-Coolant Accident
Conditions, which was issued in November 2009. The licensee issued PERs 203852
and 155933 to evaluate the concern. The licensees evaluation documented that an
operability limit of 235F for RHR suction line temperature had been previously
determined, and was reflected in current operations procedures. The inspectors
reviewed operations procedure 0-GO-1, Unit Startup From Cold Shutdown to Hot
Standby, revision 54, which required that RHR shall be removed from service prior to
exceeding 235F to avoid operability issues. This procedure, as well as 0-GO-7, Unit
Shutdown From Hot Standby to Cold Shutdown, revision 59, and 0-SO-74-1, Residual
Enclosure
16
Heat Removal System, revision 69, stated that RHR must be considered inoperable for
ECCS if shutdown cooling is in service with RCS greater than 235F.
The inspectors reviewed the engineering design calculation which had been performed
to establish the RHR system temperature limit to maintain ECCS operability. Calculation
SQN-SQS2-0155, Safety limit and setpoint for the maximum RHR pump temperature to
avoid flashing at the pump suction when aligned to the RWST, revision 1, established
the RHR temperature limit of 235F which was then incorporated into operations
procedures as being a system operability limit. The inspectors noted that this calculation
was last reviewed and approved in November 1996. The inspectors identified that some
of the parameters used in this calculation were derived from another calculation which
had been superseded in 1999 by another calculation which had since been revised there
times. The inspectors also identified that the calculation was non-conservative in that it
failed to account for maintaining the minimum net positive suction head (NPSH) required
for the RHR pumps to operate. The licensee generated PER 215434 to evaluate these
concerns. The calculation was revised and resulted in a new operability limit of 200F.
Operations procedures were revised to reflect the new operability limit.
The inspectors identified that on a number of occasions the RHR system had been
operated at temperatures exceeding the newly determined operability limit, and that the
licensee had not evaluated this condition for potential reportability based on periods of
potential past inoperability. The inspectors identified examples of when both trains of
RHR were in service above the limit in Mode 4 and 1 train of ECCS was required by TS
LCO 3.5.3 to be operable. The inspectors also identified examples of when the in-
service train of RHR was secured above the temperature limit in Mode 4, with
subsequent Mode 3 entry, where 2 trains of ECCS were required by TS LCO 3.5.2 to be
operable. The licensee entered this concern into their corrective actions program as
PER 234373. The inspectors reviewed the licensees past operability evaluation, which
concluded that, for the most limiting example of operation of both trains above the limit in
Mode 4, reasonable assurance of system operability was demonstrated to be maintained
based on proceduralized operator actions to cool the RHR suction lines in the event of a
design basis event. For the most limiting case of securing one RHR train above the
temperature limit in Mode 4 prior to Mode 3 entry, the actual system temperature was
evaluated to have been below the maximum limit for operability at the time of the Mode
change.
Analysis. The licensees failure to provide adequate design control measures for
verifying the adequacy of the design calculation used to establish the maximum RHR
operating temperature limit for maintaining ECCS operability was a performance
deficiency. The finding was determined to be greater than minor because it was similar
to example 3.j. of IMC 0612 Appendix E in that the non-conservatism in the calculation
resulted in a condition where reasonable doubt existed as to the operability of the ECCS
system. Additionally, it was associated with the Procedure Quality attribute of the
Mitigating Systems cornerstone and affected the cornerstone objective to ensure the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. Specifically, plant procedures for RHR system
operation contained non-conservative temperature limits for ensuring TS operability, and
actual system temperatures exceeded the revised appropriate limit on several
Enclosure
17
occasions. Using IMC 0609, Significance Determination Process, Attachment 4,
Phase 1 - Initial Screening and Characterization of Findings, the finding was
determined to be of very low safety significance (Green) since the finding did not
represent an actual loss of safety function.
No cross-cutting aspect was identified since the issue was not reflective of current
licensee performance, since the previous calculation in question was last revised and
approved in 1996.
Enforcement. 10 CFR 50 Appendix B Criterion III required, in part, that design control
measures shall provide for verifying or checking the adequacy of design, such as by the
use of calculational methods. Contrary to this, on November 4, 1996, the licensee failed
to provide adequate design control measures for verifying the adequacy of design
calculation SQN-SQS2-0155, revision 1, to meet its intended purpose of determining a
limiting parameter for maintaining the operability of a safety system. Consequently,
several instances occurred where actual system temperatures exceeded the design
temperature limit during system operating conditions. Corrective actions have been
taken to revise operations procedures to reflect the corrected temperature limit from a
revised calculation. Because this violation was determined to be of very low safety
significance and has been entered into the licensees corrective action program as PER
215434, it is being treated as an NCV consistent with Section 2.3.2 of the NRC
Enforcement Policy: NCV 05000327,328/2010004-02, Non-conservative Design
Calculation for RHR Suction Temperature Limit.
4OA3 Event Follow-up
.1 Inadvertent transfer of inventory from the spent fuel pit (SFP) to the Unit 1 refueling
water storage tank (RWST)
a. Inspection Scope
On June 8, 2010, the inspectors responded to a high level condition in the Unit 1 RWST
that resulted from an inadvertent transfer of water inventory from the SFP to the Unit 1
RWST. The SFP filter was being replaced while the Unit 1 RWST was on purification
recirculation and purification filters bypassed. This resulted in a system alignment of the
SFP cooling/purification system which established an unintended flowpath from the SFP
to the Unit 1 RWST. Operators responded to RWST Make-Up Shutoff and Spent Fuel
Pit Level High-Low alarms by promptly recognizing and correcting the condition.
Operators referenced TS LCO 3.5.5 which required that an inoperable RWST (due to
high level) be restored to operable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, or the Unit would have to be shut down
within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The RWST level was restored within the operable band within
approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 10 minutes. Approximately 2,800 gallons of inventory was
transferred.
The inspectors discussed the event with operations, engineering, and licensee
management personnel to gain an understanding of the event and assess follow-up
actions. The inspectors reviewed operator actions taken to determine whether they
were in accordance with licensee procedures and TS, and reviewed unit and system
Enclosure
18
indications to verify whether actions and system responses were as expected and
designed. The event was reported to the NRC as EN 45520, and documented in the
licensees CAP as PER 233652. Planned corrective actions included a revision to the
SFP cooling system operating procedure to preclude the establishment of the abnormal
system alignment that resulted in this event.
b. Findings
No findings were identified.
.2 Fire in A Intertie Transformer
a. Inspection Scope
On September 22, 2010, the inspectors responded to a fire in the A phase intertie
transformer in the switchyard, which serves as a connection between the 161-kV and
500-kV switchyards inside the sites protected area. Operators responded by
dispatching fire operations personnel to extinguish the fire. Both operating Units were
unaffected by the loss of the transformer. The inspectors discussed the event with
operations, engineering, and licensee management personnel to gain an understanding
of the event and assess follow-up actions. The inspectors reviewed operator actions
taken to determine whether they were in accordance with licensee procedures and TS,
and reviewed unit and system indications to verify whether actions and system
responses were as expected and designed. The inspectors verified that required
redundant and independent offsite power supplies to both Units remained operable, and
that no safety-related equipment was affected by the fire. The inspectors also
independently verified that the licensee had appropriately classified the event in
accordance with EPIP-1, Emergency Plan Classification Matrix, revision 44. The event
was appropriately classified as a Notice of Unusual Event for a fire within the protected
area lasting more than 15 minutes. The inspectors verified that the licensees event
classification and notifications to local authorities and NRC were performed timely. The
inspectors also reviewed the initial licensee notifications to verify that they met the
requirements specified in NUREG-1022, Event Reporting Guidelines. The event was
reported to the NRC as EN 46270, and documented in the licensees CAP as PERs
257350.
b. Findings
No findings were identified.
.3 Unit 2 Condensate Booster Pump Trip and Thermal Power Transient
a. Inspection Scope
On September 28, 2010, Unit 2 experienced a loss of one condensate booster pump.
The inspectors discussed the event with operations, engineering, and licensee
management personnel to gain an understanding of the event and assess follow-up
actions. The inspectors reviewed operator actions taken to determine whether they
Enclosure
19
were in accordance with licensee procedures and TS, and reviewed unit and system
indications to verify whether actions and system responses were as expected and
designed. The event was documented in the licensees CAP as PER 259098.
b. Findings
Introduction. The inspectors identified a Green non-cited violation of Unit 2 TS 6.8,
Procedures and Programs, for the failure to take prompt action to maintain 10-minute
average reactor thermal power less than the licensed power limit of 3455 megawatts
thermal (MWt) in response to a transient caused by the loss of a condensate booster
pump, as required by station procedures.
Description. Facility operating license DRP-79 condition 2.(C).1 stated that TVA is
authorized to operate the [Unit 2] facility at reactor core power levels not in excess of
3455 MWt. On September 28, 2010, Unit 2 operators responded to a condensate
booster pump trip by implementing the applicable portion of AOP-S.04, Condensate or
Heater Drains Malfunction, revision 15, section 2.5, Condensate Booster Pump Trip.
Step 3 of this section of the procedure required operators to monitor reactor power, and
reduce turbine load as necessary to maintain 10-minute average power less than the
3455 MWt limit. Operators noted that average power was above the licensed limit
during the transient and allowed the automatic response of the feedwater control system
to restore reactor power with no operator actions. The 10-min average of thermal power
was above the licensed limit for 8 minutes beginning 10 minutes after the pump trip, and
again for an additional 5-minute period beginning 32 minutes after the pump trip, with no
operator action taken to reduce power. Peak 10-minute average power was 3481 MWt,
and peak instantaneous power was 3515 MWt.
The inspectors reviewed Regulatory Issue Summary 2007-21, Rev. 1, Adherence To
Licensed Power Limits, which endorsed an NEI Position Statement Guidance To
Licensees on Complying with the Licensed Power Limit. This included guidance that
licensees are expected to take prompt action to reduce thermal power whenever it is
found above the licensed limit. The inspectors found the following licensee
proceduralized operating requirements:
OPDP-1, Conduct of Operations, revision 18, stated that if the unit is determined to be
operating above its licensed core thermal power limit take prompt (typically no more than
10 minutes from the time of determination) action to reduce power below the core
thermal power limit.
0-GO-5, Normal Power Operation, revision 67, stated that every effort should be made
to maintain core thermal power 10 minute average less than 3455 MWt. This procedure
further required that the 10 minute average power be trended and monitored for
increasing power trends above 3455 MWt, and if such an increasing trend is observed,
ensure prompt action is taken to decrease reactor power as necessary.
2-PI-OPS-000-022.1, Operator At The Controls Duty Station Checklists Modes 1-4,
revision 44, stated that every effort to maintain core thermal power 10 minute average
less than 3455 MWt should be made. It further required that the 10 minute average
Enclosure
20
power be monitored, and if core thermal power 10 minute average exceeds 3455 MWt
or an increasing trend which will exceed 3455 MWt is observed, then ensure prompt
action is taken to decrease reactor power as necessary.
The inspectors determined that the licensee did not meet procedural requirements to
promptly take action to decrease reactor power as necessary to maintain reactor power
below the licensed core thermal power limit.
Analysis. The licensees failure to follow procedural requirements to maintain 10-minute
average thermal power less than the licensed limit was a performance deficiency. The
finding was determined to be greater than minor because it was similar to example 8.b.
of IMC 0612 Appendix E. Additionally, it was associated with the human performance
attribute of the barrier integrity cornerstone and affected the cornerstone objective
relative to the fuel cladding barrier since operation above the licensed power limit
reduces analyzed margins to fuel cladding damage. Using IMC 0609, Significance
Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization
of Findings, the finding was determined to be of very low safety significance (Green)
since only the fuel cladding barrier was affected.
The cause of this finding was determined to have a cross-cutting aspect of Conservative
Assumptions and Safe Actions in the area of Human Performance associated with the
Decision Making component. The decision to take no operator action in response to the
thermal power transient reflected a non-conservative assumption that average thermal
power could be allowed to exceed the licensed limit without operator action while the
feedwater control system responded to the transient associated with the condensate
pump failure H.1(b).
Enforcement. Unit 2 TS 6.8.1.a required, in part, that written procedures be established,
implemented, and maintained covering the activities specified in Appendix A, Typical
Procedures for Pressurized Water Reactors and Boiling Water Reactors, of Regulatory
Guide (RG) 1.33, Quality Assurance Program Requirements (Operations), Revision 2,
dated February 1978. RG 1.33 Appendix A, Section 6.r, required procedures for
combating expected transients. Station procedure AOP-S.04, Condensate or Heater
Drains Malfunction, revision 15, was required to be implemented in response to the loss
of a condensate booster pump. Contrary to the above, on September 28, 2010, the
licensee failed to take prompt action to maintain 10-minute average thermal power less
than the applicable limit (3455 MWt) as required by AOP-S.04 section 2.5 step 3.b.
Consequently, 10-minute average thermal power was above 3455 MWt on two
occasions for a total duration of 13 minutes. Because this violation was determined to
be of very low safety significance and has been entered into the licensees corrective
action program as PER 259098, it is being treated as an NCV consistent with Section
2.3.2 of the NRC Enforcement Policy: NCV 05000328/2010004-03, Failure to Maintain
Thermal Power Less Than Licensed Limit.
Enclosure
21
.4 (Closed) LER 05000327,328/2010-001-00, Inoperability of shutdown board because of
spent fuel pool back-up pump breaker inoperability
a. Inspection Scope
On April 5, 2010, licensee maintenance personnel identified that a breaker had been
installed in the 2A1-A 480-V shutdown board without arc chutes and phase barriers
approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> prior to discovery of the condition. This resulted in the shutdown
board being declared inoperable until action could be completed to remove the affected
breaker. The licensee documented the issue in PER 224150, which included a root
cause analysis.
The inspectors discussed the event with operations, maintenance, engineering, and
licensee management personnel to gain an understanding of the conditions leading up
to the event and assess licensee actions taken following the event. Additionally, the
inspectors reviewed the root cause report to assess the detail and thoroughness of the
evaluation and the adequacy of the proposed corrective actions.
The inspectors reviewed the LER and PER 224150 to verify that the cause of the
improper breaker installation was identified and whether corrective actions were
appropriate. The cause of the event was determined to be an inadequate technical
review process which failed to identify that steps required to assemble the breaker in an
operable condition were omitted from the applicable work order. The inspectors
concluded that the licensees corrective actions to this event were appropriate.
Immediate actions included removal of the affected breaker in order to restore the
shutdown board to an operable status, and a stand-down briefing of the event to
maintenance personnel. Additional corrective actions included revision of the licensees
procedure for technical review of work order content to strengthen and clarify
requirements for technical review.
This LER is closed.
b. Findings
One licensee-identified violation was identified and is documented in section 4OA7 of
this report.
4OA5 Other Activities
.1 Quarterly Resident Inspector Observations of Security Personnel and Activities
a. Inspection Scope
During the inspection period, the inspectors conducted observations of security force
personnel and activities to ensure that the activities were consistent with licensee
security procedures and regulatory requirements relating to nuclear plant security.
These observations took place during both normal and off-normal plant working hours.
Enclosure
22
These quarterly resident inspector observations of security force personnel and activities
did not constitute any additional inspection samples. Rather, they were considered an
integral part of the inspectors normal plant status review and inspection activities.
b. Findings
No findings were identified.
.2 (Closed) Unresolved Item (URI) 05000327,328/2009006-02, Inadequate Scoping of
SSCs Used in EOPs into the Maintenance Rule Program
This URI was opened on August 28, 2009 in IR 05000327,328/2009-006 based on the
need to evaluate the potential existence of violations of 10 CFR 50.65(b)(2)(i) for plant
components which are used in EOPs not being scoped in the maintenance rule
monitoring program. The inspectors have reviewed the licensees actions to address
this issue as discussed in section 4OA2.2 of this report. This URI is closed.
4OA6 Meetings
Exit Meeting Summary
On October 7, 2010, the resident inspectors presented the inspection results to Mr. Chris
Church and other members of his staff, who acknowledged the findings. The inspectors
asked the licensee whether any of the material examined during the inspection should
be considered proprietary. No proprietary information was identified.
4OA7 Licensee-identified Violations
The following violation of very low safety significance (Green) was identified by the
licensee and is a violation of NRC requirements that meets the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.
Unit 2 TS 6.8.1.a required, in part, that written procedures be established, implemented,
and maintained covering the activities specified in Appendix A, Typical Procedures for
Pressurized Water Reactors and Boiling Water Reactors, of Regulatory Guide (RG)
1.33, Quality Assurance Program Requirements (Operations), Revision 2, dated
February 1978. RG 1.33 Appendix A Section 9.a required that maintenance that can
affect the performance of safety-related equipment should be properly pre-planned and
performed in accordance with written procedures, documented instructions, or drawings
appropriate to the circumstances. Contrary to the above, on April 5, 2010, written
procedures appropriate to the circumstances were not established which adequately
prescribed the performance of maintenance that could affect the performance of safety-
related equipment. Specifically, the maintenance instructions for reassembly of the SFP
pump C-S backup breaker failed to include instructions for proper reassembly, which
resulted in the breaker being installed in the 2A1 shutdown board and restored to service
without arc chutes, causing the shutdown board to be inoperable for greater than its TS
allowed outage time. The licensee entered the issue into the corrective action program
Enclosure
23
as PERs 228519 and 228818. The finding was determined to have very low safety
significance (Green) because there was no actual loss of safety system function, and
there was no significant increase in the likelihood of a fire.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
S. Bowman, Licensing Engineer
C. Church, Site Vice President
R. Detwiler, Director Safety and Licensing
J. Dvorak, Outage and Site Scheduling Manager
D. Foster, Performance Improvement Manager
J. Furr, Quality Assurance Manager
Z. Kitts, Licensing
R. Krich, Licensing Vice President
K. Langdon, Plant Manager
T. Marshall, Maintenance and Modifications Manager
S. McCamy, Radiation Protection Manager
M. McDowell, Corporate Project Manager
W. Nurnberger, Chemistry/Environmental Manager
D. Porter, Operations Procedures
R. Proffitt, Licensing Engineer
P. Simmons, Operations Manager
R. Thompson, Emergency Preparedness Manager
B. Wetzel, Director, Safety and Licensing
K. Wilkes, Operations Superintendent
J. Williams, Site Engineering Director
S. Young, Site Security Manager
NRC personnel
W. Rogers, Region II, Senior Reactor Analyst
S. Lingam, Project Manager, Office of Nuclear Reactor Regulation
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000327,328/2010004-01 NCV Inadequate Inspection of Raw Water Side of
Containment Spray Heat Exchangers
(Section 1R07)
05000327,328/2010004-02 NCV Non-conservative Design Calculation for
RHR Suction Temperature Limit (Section
4OA2.3)05000328/2010004-03 NCV Failure to Maintain Thermal Power Less
Than Licensed Limit (Section 4OA3.3)
Attachment
2
Closed
05000327,328/2010-001-00 LER Inoperability of shutdown board because of
spent fuel pool back-up pump breaker
inoperability (Section 4OA3.4)
05000327,328/2009006-02 URI Inadequate Scoping of SSCs Used in EOPs
into the Maintenance Rule Program
(Section 4OA5.2)
LIST OF DOCUMENTS REVIEWED
Section R04: Equipment Alignment
1,2-47W803-2, Flow Diagram-Auxiliary Feedwater, Revision 64
Section R05: Fire Protection
General Engineering Specification G-73, Installation, Modifications, and Maintenance of Fire
Protection Systems and Features, Revision 5
Sequoyah Fire Drill Critique Form, Revision 5
MMTP-102, Erection of Scaffolds/Temporary Work Platforms and Ladders, Revision 4
0-SI-FPU-247-001.0, Appendix R Emergency Lighting Auxiliary Building Quarterly test, Revision
18
FPDP-1, Conduct of Fire Protection, Revision 1
0-PI-FPU-317-299.W, Fire Protection Miscellaneous Inspections, Revision 30
Section R06: Flood Protection Measures
1,2-47W853-1, Flow Diagram Station Drainage-Control/Turbine/Service Building, Revision 17
1,2-47W853-3, Flow Diagram Station Drainage-Control/Turbine Building, Revision 6
1,2-47W853-4, Flow Diagram Station Drainage-Control/Turbine Building, Revision 11
1,2-47W853-5, Flow Diagram Station Drainage-Control/Turbine Building, Revision 7
Section R07: Heat Sink Performance
SPP-9.7, Corrosion Control Program, revision 17
0-TI-SXX-000-146.0, Program for implementing NRC Generic Letter 89-13, revision 3
SPP-9.14, Generic Letter (GL) 89-13 Implementation, revision 2
WO 09-777986-000, Cntmt spray heat exch 1A clam inspection
WO 09-782086-000, Cntmt spray heat exch 2A clam inspection
WO 09-782087-000, Cntmt spray heat exch 2B clam inspection
WO 09-777985-000, Cntmt spray heat exch 1B clam inspection
Section R12: Maintenance Rule Implementation
TI-4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -
10CFR50.65, Revision 22
PERs 177904, 204589, 227496
Attachment
3
CDEs 2286, 2296, 2516
CDEs - System 43 and 88
Section R13: Maintenance Risk Assessments and Emergent Work Evaluation
Sentinel Risk Model runs dated July 7 and 8, 2010
0-TI-DSM-000-007.1, Risk Assessment Guidelines, Revision 9
SPP-7.3, Work Activity Risk Management Process, Revision 5
MSS Daily Schedule Report-24 hour look-ahead, dated July 7, 2010
SPP-7.2.4, Forced Outage or Short Duration Planned Outage Management, Revision 1
SPP-7.2, Outage Management, Revision 18
GOI-6, Apparatus Operations, Revision 134
0-GO-16, System Operability Checklists, Revision 9
MMTP-103A, NPG Lifting and Rigging Manual, Revision 1
MMTP-103, Nuclear Power Group Movement of Items Using Overhead Handling Equipment,
Revision 2
Sentinel Risk Model run dated July 29, 2010
PSO-SPP-10.303, System Alerts, Revision 3
PRA Evaluation Response SQN-0-10-099
NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear
Power Plants, Section 11, Assessment of Risk Resulting From Performance of maintenance
Activities
0-SI-OPS-082-007.W, AC Electrical Power Source Operability Verification, revision 17
Section R15: Operability Evaluations
FSAR Section 6.2.3, Containment Air Purification and Cleanup System
FSAR Figure 9.4.7-1, Reactor Building Air Flow
FSAR Section 3.5.5, Missile Barrier Features, Buried Piping
FSAR Section 6.3.2.2, Emergency Core Cooling System
WO 09-777416-002, Reinstall Missile Shield Concrete - Diesel Generator Building
General Engineering Specification G-2, Plain and Reinforced Concrete, Revision 8
0-SI-OPS-065-017.A, Containment Shield Building Emergency Gas Treatment System Flow
Train A, Revision 14
0-SI-OPS-065-017.B, Containment Shield Building Emergency Gas Treatment System Flow
Train B, Revision 13
0-SI-OPS-065-135.0, EGTS Cleanup Subsystem Automatic Start, Revision 17
0-SO-65-1, Emergency Gas Treatment System Air Cleanup and Annulus Vacuum, Revision 19
1-SI-SLR-062-632.B, Auxiliary Building Chemical and Volume Control System Unit 1 Train B
External Leakage, Revision 4
0-MI-MRR-062-001.0, Inspection/Repair of CVCS Centrifugal Charging Pump Seals, Revision
12
NEDP-22, Functional Evaluations, Revision 8
IEEE 450-2002, IEEE Recommended Practice for Maintenance, Testing, and Replacement of
Vented Lead-Acid Batteries for Stationary Applications
IEEE Std 404-2006, IEEE Standard for Extruded and Laminated Dielectric Shielded Cable
Joints Rated 2500V to 500,000 V
Drawing 1,2-47W454-1, Mechanical Fuel Pool Cooling and Cleaning System, revision 2
Drawing 1,2-47W454-4, Mechanical Fuel Pool Cooling and Cleaning System, revision 6
Attachment
4
Design Criteria Document SQN-DC-V-3.0, The Classification of Piping, Pumps, Valves, and
Vessels, revision 17
Calculation SCG4M01131, Scaffold wired to 1B CS Heat Exchanger Vent/Drain Line, revision 0
Drawing 1, 2-45N657-5. Wiring Diagrams Separation & Misc Aux Rlys, revision 19
Section R18: Plant Modifications
SPP-9.5, Temporary Alterations, Revision 10
1,2-47W840-1, Flow Diagram-Fuel Oil, Atomizing Air and Steam, Revision 44
WO 110842725, TACF implementation for EDG 1A
WO 110842737, TACF implementation for EDG 2A
WO 110842731, TACF implementation for EDG 1B
WO 110842751, TACF implementation for EDG 2B
Section R19: Post Maintenance Testing
0-MI-IEQ-000-001.0, EQ Maintenance for 10CFR50.49 Equipment Fluid Components, (EQ
Binder SQNEQ-IFS-001), Revision 11
MMDP-3, Guidelines for Planning and Execution of Troubleshooting Activities, Revision 5
SPP-6.5, Foreign Material Control, Revision 14
MMDP-1, Maintenance Management System, Revision 18
MMDP-3, Guidelines for Planning and Execution of Troubleshooting Activities, Revision 6
SPP-6.1, Work Order Process Initiation, Revision 8
SPP-8.1, Conduct of Testing, Revision 6
1-SI-EDC-003-180.0, Setpoint Verification and Calibration of Aux Feedwater Suction Transfer
System 3 Time Delay Relays, Revision 8
1-45W1614-12, Wiring Diagram Aux Feedwater Pump and Turbine Connection Diagrams,
Revision 1
1, 2-45N657-5, Wiring Diagrams Separation and Misc Aux Relays Schematic Diagrams,
Revision 19
MI-10.54, Diesel Generator Battery Replacement and/or Battery Bank Bus Rework, Revision 20
1-SO-3-2, Auxiliary Feedwater System, revision 44
WO 111143594, Auxiliary Feedwater Pump Flow Controller
Section R22: Surveillance Testing
SPP-8.1, Conduct of Testing, Revision 5
0-SI-NUC-000-007.0, Measurement of the At-Power Moderator Temperature Coefficient,
Revision 16
1-47W811-1, Flow Diagram Safety Injection System, Revision72
Section 4OA2: Identification and Resolution of Problems
SPP-3.9, Operating Experience Program, revision 3
Calculation MDQ0072-980034, CCP, SIP, CSP, and RHR Pump NPSH Evaluation, revision 3
NRC Information Notice 2010-11, Potential For Steam Voiding Causing Residual Heat Removal
System Inoperability
Westinghouse Nuclear Safety Advisory Letter (NSAL) 09-8, Presence of Vapor in Emergency
Core Cooling System/Residual Heat Removal System in Modes 3/4 Loss-of-Coolant Accident
Conditions
0-GO-1, Unit Startup From Cold Shutdown to Hot Standby, revision 54
0-GO-7, Unit Shutdown From Hot Standby to Cold Shutdown, revision 59
Attachment
5
0-SO-74-1, Residual Heat Removal System, revision 69
Calculation SQN-SQS2-0155, Safety limit and setpoint for the maximum RHR pump
temperature to avoid flashing at the pump suction when aligned to the RWST, revision 1
Calculation SQN-SQS2-0155, Shutdown LOCA Analysis for the ECSC System, Core Cooling,
and Containment Including RHR Pump NPSH Considerations, revision 2
Section 4OA3: Event Followup
AOP-P.06, Loss of Unit 2 Electrical Shutdown Boards, revision 15
0-SO-78-1, Spent Fuel Pit Coolant System, revision 45
2-AR-M1-B, Electrical Control Board 2-XA-55-1B, revision 19
AOP-S.04, Condensate or Heater Drains Malfunction, revision 15
OPDP-1, Conduct of Operations, revision 18
0-GO-5, Normal Power Operation, revision 67
2-PI-OPS-000-022.1, Operator At The Controls Duty Station Checklists Modes 1-4, revision 44
EPIP-1, Emergency Plan Classification Matrix, revision 44
EPIP-2, Notification of Unusual Event, revision 29
Section 4OA5: Other Activities
0-PI-SQS-000-647.W, Explosive Detector Performance Test, Revision 12
0-PI-SQS-000-643.W, X-ray Equipment Function Test, Revision 13
0-PI-SQS-000-646.W, Metal Detector Functional Test, Revision 10
Attachment