ML091200497
| ML091200497 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 04/30/2009 |
| From: | Marvin Sykes NRC/RGN-II/DRP/RPB3 |
| To: | Nazar M Florida Power & Light Co |
| References | |
| IR-09-002 | |
| Download: ML091200497 (33) | |
See also: IR 05000335/2009002
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
SAM NUNN ATLANTA FEDERAL CENTER
61 FORSYTH STREET, SW, SUITE 23T85
ATLANTA, GEORGIA 30303-8931
April 30, 2009
Mr. Mano Nazar
Executive Vice President, Nuclear and Chief Nuclear Officer
Florida Power and Light Company
P.O. Box 14000
Juno Beach, FL 33408-0420
SUBJECT:
ST. LUCIE NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT
05000335/2009002, 05000389/2009002
Dear Mr. Nazar:
On March 31, 2009, the US Nuclear Regulatory Commission (NRC) completed an inspection at
your St. Lucie Plant. The enclosed integrated inspection report documents the inspection
findings which were discussed on April 2, 2009, with Mr. Johnston and other members of your
staff.
The inspection examined activities conducted under your license as they related 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 and one self-revealing finding, all of very
low safety significance (Green). Additionally, one licensee-identified violation which was
determined to be of very low safety significance is listed in Section 4OA7 of this report. These
findings were determined to involve violations of NRC requirements. However, because of the
very low safety significance and because they are entered into your corrective action program,
the NRC is treating the findings as non-cited violations (NCVs) consistent with Section VI.A.1 of
the NRC Enforcement Policy. If you contest any NCV or disagree with an assigned cross-
cutting aspect in this report, you should provide a response within 30 days of the date of this
inspection report, with the basis for your denial or disagreement, 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
St. Lucie facility. 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 St. Lucie Nuclear Plant. The information you provide will be
considered in accordance with Inspection Manual Chapter 0305
2
In accordance with 10 CFR 2.390 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 the 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/
Marvin D. Sykes, Chief
Rector Projects Branch 3
Division of Reactor Projects
Docket Nos.: 50-335, 50-389
Enclosure: Inspection Report 05000335/2009002, 05000389/2009002
w/Attachment: Supplemental Information
cc w/encl: (See page 3)
_________________________
XG SUNSI REVIEW COMPLETE
OFFICE
RII:DRP
RII:DRP
RII:DRP
RII:DRP
RII:DRS
SIGNATURE
JHamman for
TLH4
HGepford for
NAME
SNinh
MSykes
THoeg
SSanchez
LMiller
DATE
04/30/2009
04/30/2009
04/30/2009
04/30/2009
04/30/.2009
5/ /2009
5/ /2009
E-MAIL COPY?
YES
NO YES
NO YES
NO YES
NO YES
NO YES
NO YES
NO
3
cc w/encl:
Gordon L. Johnston
Site Vice President
St. Lucie Nuclear Plant
Electronic Mail Distribution
Christopher R. Costanzo
Plant General Manager
St. Lucie Nuclear Plant
Electronic Mail Distribution
Mark Hicks
Operations Manager
St. Lucie Nuclear Plant
Electronic Mail Distribution
Eric Katzman
Licensing Manager
St. Lucie Nuclear Plant
Electronic Mail Distribution
Abdy Khanpour
Vice President
Engineering Support
Florida Power and Light Company
P.O. Box 14000
Juno Beach, FL 33408-0420
Robert J. Hughes
Director
Licensing and Performance Improvement
Florida Power & Light Company
Electronic Mail Distribution
Alison Brown
Nuclear Licensing
Florida Power & Light Company
Electronic Mail Distribution
M. S. Ross
Managing Attorney
Florida Power & Light Company
Electronic Mail Distribution
Marjan Mashhadi
Senior Attorney
Florida Power & Light Company
Electronic Mail Distribution
William A. Passetti
Chief
Florida Bureau of Radiation Control
Department of Health
Electronic Mail Distribution
Craig Fugate
Director
Division of Emergency Preparedness
Department of Community Affairs
Electronic Mail Distribution
J. Kammel
Radiological Emergency Planning
Administrator
Department of Public Safety
Electronic Mail Distribution
Mano Nazar
Senior Vice President and Nuclear Chief
Operating Officer
Florida Power & Light Company
Electronic Mail Distribution
Peter Wells
(Acting) Vice President, Nuclear
Training and Performance Improvement
Florida Power and Light Company
P.O. Box 14000
Juno Beach, FL 33408-0420
Mark E. Warner
Vice President
Nuclear Plant Support
Florida Power & Light Company
Electronic Mail Distribution
Faye Outlaw
County Administrator
St. Lucie County
Electronic Mail Distribution
Jack Southard
Director
Public Safety Department
St. Lucie County
Electronic Mail Distribution
4
Letter to Mano Nazar from Marvin D. Sykes dated April 30, 2009
SUBJECT:
ST. LUCIE NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT
05000335/2009002, 05000389/2009002
Distribution w/encl:
C. Evans, RII
L. Slack, RII
OE Mail
RIDSNRRDIRS
PUBLIC
RidsNrrPMStLucie Resource
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-335, 50-389
License Nos:
Report No:
05000335/2009002, 05000389/2009002
Licensee:
Florida Power & Light Company (FP&L)
Facility:
St. Lucie Nuclear Plant, Units 1 & 2
Location:
6351 South Ocean Drive
Jensen Beach, FL 34957
Dates:
January 1 to March 31, 2009
Inspectors:
T. Hoeg, Senior Resident Inspector
S. Sanchez, Resident Inspector
S. Ninh, Senior Project Engineer
L. Miller, Senior Reactor Inspector
R. Bernhard, Senior Reactor Analyst
Approved by:
M. Sykes, Chief
Reactor Projects Branch 3
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000335/2009-002, 05000389/2009-002; 01/01/2009 - 3/31/2009; St. Lucie Nuclear Plant,
Units 1 & 2; Event Follow-up, Other Activities, Surveillance Testing, Identification and
Resolution of Problems.
The report covered a three month period of inspection by resident inspectors and several region
based inspectors. The significance of most findings is identified by their color (Green, White,
Yellow, Red) using IMC 0609, Significance Determination Process (SDP). Findings for which
the SDP does not apply may be Green or be assigned a severity level after NRC management
review. The NRCs program for overseeing the safe operation of commercial nuclear power
reactors is described in NUREG-1649, Reactor Oversight Process, and Revision 4, dated
December 2006.
A.
Inspector Identified & Self-Revealing Findings
Cornerstone: Initiating Events
Green. A self-revealing finding was identified for failure to implement adequate process
controls to minimize risk during maintenance on the Unit 2, 5B feedwater heater high
level limit switch resulting in a manual reactor trip on June 4, 2008. No violations of
NRC requirements were identified because the feedwater heater drain system is non-
safety related. The licensee entered the issue into the corrective action program as
condition report (CR) 2008-18858. Corrective actions included development of specific
procedural direction for controlling and insulating energized control circuit leads during
work evolutions using the risk management process, design modifications to address
vulnerability when performing maintenance on level switches, and evaluation of industry
best practices for training and handling of energized leads.
The finding was more than minor because it resulted in a manual reactor trip. The
finding was associated with the human performance attribute and affected the Initiating
Events cornerstone objective of limiting the likelihood of those events that upset plant
stability and challenge critical safety functions during shutdown as well as at power
operations. Using the NRC Manual Chapter 0609, ASignificance Determination
Process,@ Attachment 609.04, Phase 1 screening worksheet, the finding was determined
to be of very low safety significance because it was a transient initiator but did not
increase the likelihood that mitigation equipment would not be available. The cause of
the finding is related to the cross-cutting area of Human Performance, with a work
control component. Specifically, the licensee did not adequately plan work activities to
minimize the risk of grounding the energized leads (H.3(a)). (Section 4OA3).
Cornerstone: Mitigating Systems
Green. The inspectors identified a Green noncited violation of Technical Specifications 3.8.1, AC Sources, for failure to perform a required monthly surveillance test in its
entirety. Specifically, the inspectors identified that St. Lucie has not performed Unit 1
Emergency Diesel Generator (EDG) technical specification (TS) surveillance
requirement 4.8.1.1.2 as written to verify the fuel oil transfer pumps will transfer fuel from
3
Enclosure
the storage tank to the engine mounted day tanks at least every 31 days to demonstrate
operability. The licensee entered the finding in their CAP as CR 2009-4976.
The finding is more than minor in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening. Specifically, it
impacts the mitigating systems cornerstone objective in that it affects the operability,
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. Using Manual Chapter 0609, Significance
Determination Process, Phase 1 worksheet, this finding was determined to be of very
low safety significance since it did not represent an actual loss of a safety function. The
inspectors determined that the cause of this finding has a crosscutting aspect in the area
of human performance associated with the resources attribute, in that the operators did
not have adequate procedural guidance available to completely test the fuel oil transfer
system as required by technical specifications. (IMC 0305 aspect H.2.c). (Section
1R22)
Green. The inspectors identified a NCV of TS 6.8.1.a and Regulatory Guide (RG) 1.33,
for the licensee failing to specify and ensure an appropriate post maintenance test
(PMT) was performed as required by administrative procedure ADM-78.01, Post
Maintenance Testing. Specifically, the inspectors identified that after replacement of an
emergency diesel generator (EDG) fuel oil day tank low level instrument, an inadequate
PMT was performed because the instrument switch mechanism was not demonstrated
functional by actual lowering of the fuel oil level within the tank to actuate the float
assembly. The licensee entered the finding in their CAP as CR 2008-32722.
The finding is more than minor because it is associated with the equipment performance
attribute of the mitigating systems cornerstone. The finding was determined to have
very low safety significance because it did not result in an actual loss of safety system
function. This finding was related to the coordination of work activities attribute of the
human performance cross-cutting area in the aspect of work control (IMC 0305 aspect
H.3.b). (Section 4OA5.3)
Green. The inspectors identified a Non Cited Violation (NCV) of 10 CFR 50, Appendix
B, Criterion XVI, Corrective Action, for failure of the licensee to take timely and effective
corrective actions to prevent recurrence of Unit 1 emergency diesel generator (EDG) day
tank low level switch failures starting in 2007. Specifically, in June 2007, the licensee
performed an apparent cause evaluation of sticking level switches and determined that
a manufacturing defect associated with the packing gland of the floats pivot shaft
caused some restricted movement. The licensee also determined that extended shelf
life contributed to the failures of these level switches. However, other than replacing the
switches with new ones, the only corrective action(s) that resulted from this evaluation
were to ensure that switches manufactured before 2000 were not used for plant
applications. Subsequently, in October 2008, the 1A-EDG day tank low level switch
failed during the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> EDG run and again failed during maintenance activities in
February 2009.
4
Enclosure
The finding is more than minor because it is associated with the equipment performance
attribute of the mitigating systems cornerstone. The finding was determined to have
very low safety significance because an SDP Phase 3 analysis determined that the risk
was less than 1E-6/year. This finding was related to the corrective action attribute of the
problem identification and resolution cross-cutting area in the aspect of appropriate and
timely corrective actions (IMC 0305 aspect P.1.d). (Section 4OA2.3)
B.
Licensee Identified Violations
One violation of very low safety significance was identified by the licensee and has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into their corrective action program. This violation and corrective actions
are listed in Section 4OA7 of this report.
Enclosure
REPORT DETAILS
Summary of Plant Status:
Unit 1 and Unit 2 began the period at full Rated Thermal Power (RTP) and operated at full
power for most of the entire period. Unit 2 had an unplanned down power to 60 percent rated
thermal power to repair a turbine building cooling water pump bearing on March 5, 2009. Unit 2
returned to full power operation on March 10, 2009. Unit 2 reduced power to 85 percent rated
thermal power due to a traveling screen failure March 25, 2009. Unit 2 returned to full power
operation on March 30, 2009.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity (Reactor-R)
1R01 Adverse Weather Protection
a.
Inspection Scope
During the weeks of January 21 and February 2, 2009, the inspectors reviewed the
status of licensee actions in accordance with ADM-04.03, Cold Weather Preparations.
The inspectors verified conditions were met for entering the procedure and that
equipment status was verified as directed by the procedure. The inspectors performed a
walkdown of the following safety-related equipment on both units that are exposed to the
outside weather conditions to identify any potential adverse conditions. Condition
reports (CRs) were checked to assure that the licensee was identifying and resolving
weather related issues.
Unit 2 Emergency Diesel Generator (EDG) Rooms
Unit 1 C Auxiliary Feedwater (AFW) Pump Area
Unit 2 Main Feedwater Isolation Valve Area
Unit 1 Condensate Storage Tank Area
Unit 1 EDG Rooms
Unit 1 Refueling Water Tank (RWT)
Unit 2 RWT
b.
Findings
No findings of significance were identified.
6
Enclosure
1R04 Equipment Alignment
.1
Partial Equipment Walkdowns
a.
Inspection Scope
The inspectors conducted four partial alignment verifications of the safety-related
systems listed below. These inspections included reviews using plant lineup
procedures, operating procedures, and piping and instrumentation drawings, which were
compared with observed equipment configurations to verify that the critical portions of
the systems were correctly aligned to support operability. The inspectors also verified
that the licensee had identified and resolved equipment alignment problems that could
cause initiating events or impact the capability of mitigating systems or barriers by
entering them into the corrective action program (CAP).
1B EDG while the 1A EDG was Out of Service (OOS)
2A Component Cooling Water (CCW) System while the 2B CCW System OOS
2B Containment Spray (CS) System while the 2A CS System OOS
1B and 2B Startup Transformers while the 1A and 2A Startup Transformers OOS
b.
Findings
No findings of significance were identified.
1R05 Fire Protection
a.
Inspection Scope
.1
Fire Area Walkdowns
The inspectors toured the following five plant areas during this inspection period to
evaluate conditions related to control of transient combustibles and ignition sources, the
material condition and operational status of fire protection systems including fire barriers
used to prevent fire damage or fire propagation. The inspectors reviewed these
activities against provisions in the licensees procedure ADM-1800022, Fire Protection
Plan, and 10 CFR Part 50, Appendix R. The licensees fire impairment lists, updated on
an as-needed basis, were routinely reviewed. In addition, the inspectors reviewed the
CR database to verify that fire protection problems were being identified and
appropriately resolved. The following areas were inspected:
Unit 1 Charging Pump Areas
Unit 1 Elevation -0.5 Pipe Penetration Area
Unit 2 Electrical Penetration Rooms
Unit 2 Control Element Drive Mechanism Control System Room
Unit 2 Emergency Core Cooling System (ECCS) Pumps Room
7
Enclosure
b.
Findings
No findings of significance were identified.
.2
Fire Protection - Drill Observation
a.
Inspection Scope
The inspectors observed a fire drill conducted in the Unit 1 Turbine Building 19.5'
Elevation 1C AFW Pump Room on January 20, 2009. The drill was observed to
evaluate the overall readiness of the plant fire brigade to respond to and extinguish fires.
The inspectors verified that the licensee staff identified deficiencies, openly discussed
them in a self-critical manner at the drill debrief, and took appropriate corrective actions
as required. Specific attributes evaluated were: (1) proper wearing of turnout gear and
self-contained breathing apparatus; (2) proper use and layout of fire hoses; (3)
employment of appropriate fire fighting techniques; (4) sufficient fire fighting equipment
brought to the scene; (5) effectiveness of command and control; (6) search for victims
and propagation of the fire into other plant areas; (7) smoke removal operations; (8)
utilization of pre-planned strategies; (9) adherence to the pre-planned drill scenario; and
(10) drill objectives.
b.
Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Training Program
Resident Inspector Quarterly Review
a.
Inspection Scope
On March 30, 2009, the inspectors observed and assessed licensed operator actions
during a simulated steam generator tube leak and subsequent reactor trip with
complications, to verify that operator performance was adequate and that evaluators
were identifying and documenting crew performance problems. The exercise was
performed in accordance with St. Lucie Plant Simulator Exercise Guide 0815018,
Revision 14. The inspectors also reviewed simulator physical fidelity and specifically
evaluated the following attributes related to the operating crews performance:
Clarity and formality of communication
Ability to take timely action to safely control the unit
Prioritization, interpretation, and verification of alarms
Correct use and implementation of off-normal and emergency operation procedures;
and emergency plan implementing procedures
Control board operation and manipulation, including high-risk operator actions
8
Enclosure
Oversight and direction provided by supervision, including ability to identify and
implement appropriate technical specification actions, regulatory reporting
requirements, and emergency plan classification and notification
Crew overall performance and interactions
Effectiveness of the post-evaluation critique.
b.
Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
a.
Inspection Scope
The inspectors reviewed system performance data and associated CRs for the two
systems listed below to verify that the licensees maintenance efforts met the
requirements of 10 CFR 50.65 (Requirements for Monitoring the Effectiveness of
Maintenance at Nuclear Power Plants) and licensee Administrative Procedure ADM-17-
08, Implementation of 10CFR50.65, Maintenance Rule. The inspectors efforts focused
on maintenance rule scoping, characterization of maintenance problems and failed
components, risk significance, determination of a(1) and a(2) classification, corrective
actions, and the appropriateness of established performance goals and monitoring
criteria. The inspectors also interviewed responsible engineers and observed some of
the corrective maintenance activities. The inspectors also attended applicable expert
panel meetings and reviewed associated system health reports. The inspectors verified
that equipment problems were being identified and entered into the CAP
Unit 1 Emergency Diesel Generator System
Unit 1 Intake Cooling Water System
b.
Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a.
Inspection Scope
The inspectors completed in-office reviews, plant walkdowns, and control room
inspections of the licensees risk assessment of six emergent or planned maintenance
activities. The inspectors verified the licensees risk assessment and risk management
activities using the requirements of 10 CFR 50.65(a)(4); the recommendations of
Nuclear Management and Resource Council 93-01, Industry Guidelines for Monitoring
the Effectiveness of Maintenance at Nuclear Power Plants, Revision 3; and procedure
ADM-17.16, Implementation of the Configuration Risk Management Program. The
inspectors also reviewed the effectiveness of the licensees contingency actions to
mitigate increased risk resulting from the degraded equipment. The inspectors
9
Enclosure
interviewed responsible Senior Reactor Operators on-shift, verified actual system
configurations, and specifically evaluated results from the online risk monitor (OLRM) for
the combinations of out of service (OOS) risk significant systems, structures, and
components (SSCs) listed below:
1A HPSI Pump, Valve HCV-3627, and Fan HVS-5A OOS
1B LPSI Pump, Valve SB-37-2, and 1A AFW Pump OOS
2B Emergency Core Cooling System (ECCS) OOS
1A EDG, 1C Instrument Air Compressor, and Valve PCV-8805 OOS
1B EDG and Valve HCV-08-2B OOS
b.
Findings
No findings of significance were identified.
1R15 Operability Evaluations
a.
Inspection Scope
The inspectors reviewed the following six CR interim dispositions and operability
determinations to ensure that operability was properly supported and the affected SSCs
remained available to perform its safety function with no increase in risk. The inspectors
reviewed the applicable UFSAR, and associated supporting documents and procedures,
and interviewed plant personnel to assess the adequacy of the interim disposition.
CR 2009-2369, 1A EDG Sump Oil Temperature
CR 2009-1471, Unit 2 ECCS Piping Insulation Removed
CR 2009-2825, CEA # 85 Placed on the Lower Gripper
CR 2009-5595, 1A EDG Air Intake Screen Corroded
CR 2009-6666, 1A LPSI System Piping Air Voiding
CR 2009-2951, Unit 2 Safety Injection Tank Sample Valve Operation
b.
Findings
No findings of significance were identified
1R18 Plant Modifications
a.
Inspection Scope
The inspectors reviewed the documentation for a permanent modification affecting both
units, plant change modification PCM 07127, ECCS Piping Insulation Modification to
Support Void Inspections. The inspectors reviewed the 10 CFR 50.59 screening and
evaluation, fire protection review, environmental review, As Low As Reasonably
Achievable (ALARA) screening, and license renewal review, to verify that the
modification had not affected system operability/availability. The inspectors reviewed
10
Enclosure
associated plant drawings and UFSAR documents impacted by this modification and
discussed the changes with licensee personnel to verify that the installation was
consistent with the modification documents. Additionally, the inspectors verified that
problems associated with modifications were being identified and entered into the CAP.
b.
Findings
No findings of significance were identified.
1R19 Post Maintenance Testing
a.
Inspection Scope
For the five post maintenance tests (PMTs) listed below, the inspectors reviewed the test
procedures and either witnessed the testing and/or reviewed test records to determine
whether the scope of testing adequately verified that the work performed was correctly
completed and demonstrated that the affected equipment was functional and operable.
The inspectors verified that the requirements of procedure ADM-78.01, Post
Maintenance Testing, were incorporated into test requirements. The inspectors
reviewed the following work orders (WOs) and/or work requests (WR):
WO 38000129, Valve MV-07-2A Stroke Test and Dynamic Analysis
WO 39002591, 1A EDG Day Tank Level Switch Replacement
WO 37014539, 1B EDG Day Tank Level Switch Replacement
WO 39002134, 1A EDG Lube Oil Line Replacement
WO 38027005, Valve HCV-09-18 Oil Replacement
b.
Findings
No findings of significance were identified.
1R22 Surveillance Testing
a.
Inspection Scope
The inspectors either reviewed or witnessed the following six surveillance tests to verify
that the tests met the TS, the UFSAR, the licensees procedural requirements, and
demonstrated the systems were capable of performing their intended safety functions
and their operational readiness. In addition, the inspectors evaluated the effect of the
testing activities on the plant to ensure that conditions were adequately addressed by
the licensee staff and that after completion of the testing activities, equipment was
returned to the positions/status required for the system to perform its safety function.
The tests reviewed included one in-service test and two containment isolation valve
surveillances. The inspectors verified that surveillance issues were documented in the
CAP.
11
Enclosure
2-OSP-59.01A, 2A EDG Monthly Test
2-OSP-69.25, Unit 2 Engineered Safeguards Testing
1-OSP-59.01A, 1A EDG Monthly Test
OP-2-0010125A, Valve MV-07-2B Stroke Test
1-OSP-66.01, Unit 1 Control Element Assembly Exercise
1-OSP-9.01A, 1A AFW Pump Code Run
b.
Findings
Introduction. The inspectors identified a Green noncited violation of Technical
Specifications (TS) 3.8.1, AC Sources, for failure to perform a required monthly
surveillance test in its entirety. Specifically, the inspectors identified that St. Lucie has
not performed Unit 1 EDG TS surveillance requirement 4.8.1.1.2 as written to verify the
fuel oil transfer pumps will transfer fuel from the storage tank to the engine mounted day
tanks at least every 31 days to demonstrate operability.
Description. During the month of January, 2009, the inspectors reviewed the Unit 1
EDG monthly surveillance test procedures 1-OSP-59.01A and 1-OSP-59.01B, 1A
Emergency Diesel Generator Monthly Surveillance and 1B Emergency Diesel Generator
Monthly Surveillance prior to performing planned inspections. The inspectors
determined that procedure section 7.1 started the fuel oil transfer pump while it was
lined up in the recirculation mode to the fuel oil storage tank and did not transfer fuel to
the engine mounted day tank. The inspector concluded a verification of the pumps
ability to transfer fuel to the day tank had not been performed on a monthly basis as
required by technical specifications. The St. Lucie TS surveillance section 4.8.1.1.2 is
required to be performed as written to verify the fuel oil transfer pumps can be started
and transfer fuel from the storage tank to the engine mounted day tanks at least every
31 days to demonstrate operability.
The inspector reviewed past Unit 1 EDG monthly surveillance tests to determine if the
method of testing the fuel oil transfer pump for operability had been revised since the
plant started commercial operation in 1976. The inspector found that before 1993, the
Unit 1 EDG periodic test required by visual observation that the EDG fuel oil transfer
pump runs and actually increases level in the generator mounted tanks. In 1993, the
subject surveillance procedures were revised to run the fuel oil transfer pump in the
recirculation mode and verifying the pump discharge pressure measured a minimum of
25 psig while the fuel oil is pumped from the storage tanks back to the storage tank
versus the generator engine mounted day tanks as previously required. The practice of
not transferring fuel with the transfer pump to the day tank on a monthly basis reduced
the licensees ability to identify pump degradation and/or capability, rendering the EDGs
not fully reliable to meet a mission time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors determined that the
test procedure revision and methodology of periodically testing the operation of the fuel
oil transfer system was inadequate and may not verify full operability of the fuel oil
transfer system.
12
Enclosure
The inspectors shared their findings with the licensee and informed them that their
practice of testing the pump in the recirculation mode without verifying the transfer of fuel
to the engine mounted tank did not meet technical specification monthly surveillance test
requirements. The licensee entered the condition in their CAP as CR 2009-4976 and
took prompt action to verify compliance with the TS requirements over a two week
period. The Unit 1 EDG surveillance of the fuel oil transfer systems were tested
satisfactorily and monthly surveillance test procedures 1-OSP-59.01A and 1-OSP-
59.01B were revised to reflect the monthly TS surveillance requirement by returning to
the method of testing used before 1993 to determine operability.
Analysis. The inspectors determined that failure to perform a required TS surveillance in
its entirety is a performance deficiency. The finding is more than minor in accordance
with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports,
Appendix B, Issue Screening. Specifically, the finding impacts the mitigating systems
cornerstone objective in that it affects the operability, availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Using Manual Chapter 0609, Significance Determination Process,
Phase 1 worksheet, this finding was determined to be of very low safety significance
since it did not represent an actual loss of a safety function. The inspectors determined
that the cause of this finding has a crosscutting aspect in the area of human
performance associated with the resources attribute, in that the operators did not have
adequate procedural guidance available to completely test the fuel oil transfer system as
required by technical specifications. (MC 0305 aspect H.2.c).
Enforcement. TS 3.8.1 requires surveillance requirement 4.8.1.1.2.3.a.3 to be
performed for each diesel generator to demonstrate operability on a monthly basis.
Contrary to this requirement, the licensee failed to perform TS surveillance requirement 4.8.1.1.2.3.a since 1993. The surveillance procedure was revised in 1993 and that
method used to test the fuel oil transfer system remained in use for over 15 years and
became an accepted practice by the licensee. Since the licensee entered the issue into
their CAP as CR 2009-4976 and the finding is of very low safety significance (Green),
this violation is being treated as a noncited violation, consistent with Section VI.A of the
NRC Enforcement Policy: NCV 05000335/2009002-01: Failure to Perform a Required
TS Surveillance.
Cornerstone: Emergency Preparedness
1EP2 Alert and Notification System Testing
a.
Inspection Scope
The inspector evaluated the adequacy of licensee=s methods for testing the alert and
notification system in accordance with NRC Inspection Procedure 71114, Attachment
02, AAlert and Notification System Evaluation@. The applicable planning standard 10
CFR Part 50.47(b)(5) and its related 10 CFR Part 50, Appendix E, Section IV.D
requirements were used as reference criteria. The criteria contained in NUREG-0654,
ACriteria for Preparation and Evaluation of Radiological Emergency Response Plans and
13
Enclosure
Preparedness in Support of Nuclear Power Plants,@ Revision 1, was also used as a
reference.
The inspector reviewed various documents which are listed in the Attachment to this
report. This inspection activity satisfied one inspection sample for the alert and
notification system on a biennial basis.
b.
Findings
No findings of significance were identified.
1EP3 Emergency Response Organization (ERO) Augmentation
a.
Inspection Scope
The inspector reviewed the licensee=s Emergency Response Organization (ERO)
augmentation staffing requirements and process for notifying the ERO to ensure the
readiness of key staff for responding to an event and timely facility activation. The
qualification records of key position ERO personnel were reviewed to ensure all ERO
qualifications were current. A sample of problems identified from augmentation drills or
system tests performed since the last inspection were reviewed to assess the
effectiveness of corrective actions.
The inspection was conducted in accordance with NRC Inspection Procedure 71114,
Attachment 03, AEmergency Response Organization Staffing and Augmentation
System.@ The applicable planning standard, 10 CFR 50.47(b)(2) and its related 10 CFR
50, Appendix E requirements were used as reference criteria.
The inspector reviewed various documents which are listed in the Attachment to this
report. This inspection activity satisfied one inspection sample for the ERO staffing and
augmentation system on a biennial basis.
b.
Findings
No findings of significance were identified.
1EP4 Emergency Action Level (EAL) and Emergency Plan Changes
a.
Inspection Scope
Since the last NRC inspection of this program area, Revisions 52, 53 and 54 of the
Emergency Plan was implemented based on the licensees determination, in accordance
with 10 CFR 50.54(q), that the changes resulted in no decrease in the effectiveness of
the Plan, and that the revised Plan continued to meet the requirements of 10 CFR
50.47(b) and Appendix E to 10 CFR Part 50. The inspector conducted a sampling
review of the Plan changes and implementing procedure changes made between
January 1, 2008 and January, 2009 to evaluate for potential decreases in effectiveness
of the Plan. However, this review was not documented in a Safety Evaluation Report
14
Enclosure
and does not constitute formal NRC approval of the changes. Therefore, these changes
remain subject to future NRC inspection in their entirety.
The inspection was conducted in accordance with NRC Inspection Procedure 71114,
Attachment 04, AEmergency Action Level and Emergency Plan Changes.@ The
applicable planning standard (PS), 10 CFR 50.47(b)(4) and its related 10 CFR 50,
Appendix E requirements were used as reference criteria.
The inspector reviewed various documents which are listed in the Attachment to this
report. This inspection activity satisfied one inspection sample for the emergency action
level and emergency plan changes on an annual basis.
b.
Findings
No findings of significance were identified.
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies
a.
Inspection Scope
The inspector reviewed the corrective actions identified through the Emergency
Preparedness program to determine the significance of the issues and to determine if
repeat problems were occurring. The facility=s self-assessments and audits were
reviewed to assess the licensee=s ability to be self-critical, thus avoiding complacency
and degradation of their emergency preparedness program. In addition, the inspector
reviewed licensee self-assessments and audits to assess the completeness and
effectiveness of all emergency preparedness related corrective actions.
The inspection was conducted in accordance with NRC Inspection Procedure 71114,
Attachment 05, ACorrection of Emergency Preparedness Weaknesses.@ The applicable
planning standard, 10 CFR 50.47(b)(14) and its related 10 CFR 50, Appendix E
requirements were used as reference criteria.
The inspector reviewed various documents which are listed in the Attachment to this
report. This inspection activity satisfied one inspection sample for the correction of
emergency preparedness weaknesses on a biennial basis.
b.
Findings
No findings of significance were identified.
15
Enclosure
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1
Initiating Events and Mitigating Systems Cornerstones
a.
Inspection Scope
The inspectors checked licensee submittals for the performance indicators (PIs) listed
below for the period January 2008 through December 2008, to verify the accuracy of the
PI data reported during that period. Performance indicator definitions and guidance
contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, and
licensee procedures ADM-25.02, NRC Performance Indicators, and NAP-206, NRC
Performance Indicators, were used to check the reporting for each data element. The
inspectors checked operator logs, plant status reports, CRs, system health reports, and
PI data sheets to verify that the licensee had identified the required data, as applicable.
The inspectors interviewed licensee personnel associated with performance indicator
data collection, evaluation, and distribution.
Unit 1 Unplanned Scrams per 7000 Critical Hours
Unit 2 Unplanned Scrams per 7000 Critical Hours
Unit 1 Unplanned Scrams With Loss of Normal Heat Removal
Unit 2 Unplanned Scrams With Loss of Normal Heat Removal
Unit 1 Unplanned Transients per 7000 Critical Hours
Unit 2 Unplanned Transients per 7000 Critical Hours
b.
Findings
No findings of significance were identified.
.2
Emergency Preparedness Cornerstones
a.
Inspection Scope
The inspector sampled licensee submittals relative to the PIs listed below for the period
January 2008 through December 2008. To verify the accuracy of the PI data reported
during that period, PI definitions and guidance contained in NEI 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 5, was used to confirm the
reporting basis for each data element.
Emergency Response Organization (ERO) Drill/Exercise Performance
ERO Drill Participation
Alert and Notification System Reliability
For the specified review period, the inspector examined data reported to the NRC,
procedural guidance for reporting PI information, and records used by the licensee to
identify potential PI occurrences. The inspector verified the accuracy of the PI for ERO
16
Enclosure
drill and exercise performance through review of a sample of drill and event records.
The inspector reviewed selected training records to verify the accuracy of the PI for ERO
drill participation for personnel assigned to key positions in the ERO. The inspector
verified the accuracy of the PI for alert and notification system reliability through review
of a sample of the licensees records of periodic system tests. The inspector also
interviewed the licensee personnel who were responsible for collecting and evaluating
the PI data. Licensee procedures, records, and other documents reviewed within this
inspection area are listed in the Attachment to this report.
b.
Findings
No findings of significance were identified.
4OA2 Problem Identification and Resolution
.1
Daily Review
a.
Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems,
and to help identify repetitive equipment failures or specific human performance issues
for follow-up, the inspectors performed a screening of items entered daily into the
licensees CAP. This review was accomplished by reviewing daily printed summaries of
CRs and by reviewing the licensees electronic CR database. Additionally, reactor
coolant system unidentified leakage was checked on a daily basis to verify no
substantive or unexplained changes.
b. Findings
No findings of significance were identified.
.2
Annual Sample. 1B1 Reactor Coolant Pump Seal Flanges Found Removed With
Danger Tags Still Attached
a.
Inspection Scope
The inspectors selected CR 2008-35071, 1B1 Reactor Coolant Pump Seal Flanges
Found Removed With Danger Tags Still Attached, for a more in-depth review of the
circumstances that led up to the equipment clearance order (ECO) mishap and the
corrective actions that followed.
The inspectors reviewed the licensees evaluation of the event and the associated
corrective actions. The inspectors reviewed the apparent cause evaluation and
interviewed plant personnel. The inspectors evaluated the licensees administration of
this selected condition report in accordance with their CAP as specified in licensee
procedures PI-AA-204, Condition Identification and Screening Process, and PI-AA-205,
Condition Evaluation and Corrective Actions.
17
Enclosure
b.
Findings and Observations
On November 11, 2008, while Unit 1 was defueled during a refueling outage a
maintenance crew entered containment to begin work on installing new reactor coolant
pump (RCP) seal injection piping. The equipment clearance order (ECO) tags were still
hanging on the blank flanges that were in place to provide system boundary protection
while the new piping was being fabricated. In preparation of installing the new piping,
the workers proceeded to remove the flanges with the danger tags still attached. This
was in contrast to licensee procedure ADM-09.04, In-Plant Equipment Clearance
Orders Section 6.2, step 3.a which required at no time shall an ECO tag be removed or
ignored. The inspectors determined the apparent cause analysis of this event was
thorough and provided additional details of contributing causes. The corrective actions
taken by the licensee or planned were in accordance with their above referenced
procedures. This licensee identified finding involved a violation of TS 6.8.1, Procedures
and Programs. The enforcement aspects of this violation are discussed in Section 4OA7
of this report.
.3
Semi-Annual Trend Review
a.
Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems,
the inspectors reviewed the licensees CAP and associated documents to identify trends
that could indicate the existence of a more significant safety issue. The inspectors
selected Murphy switch failures for trending due to a number of recent failures
associated with the Unit 1 EDG fuel oil transfer system. The inspectors review was
focused on repetitive equipment issues, but also considered the results of daily inspector
CR item screening discussed in Section 4OA2.1 above, plant status reviews, plant tours,
document reviews, and licensee trending efforts. The inspectors review nominally
considered the six month period of July through December 2008. Corrective actions
associated with a sample of the issues identified in the licensees CAP were reviewed for
adequacy.
b.
Assessment and Observations
Introduction. The inspectors identified an Non Cited Violation (NCV) of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Action, for the licensee failing to take timely and
effective corrective actions to prevent recurrence of Unit 1 emergency diesel generator
(EDG) day tank low level switch failures resulting in the 1A EDG being unreliable to meet
its continuous operational mission time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, multiple repeat switch
failures occurred over a two year period where the cause of the failure was not identified
and corrected to prevent recurrence.
Description. The St. Lucie Unit 1 EDGs have engine skid mounted day tanks supplied
by a larger external storage tank for fuel supply during extended periods of operation.
The day tank fuel oil inventory is controlled by use of several Murphy level switches.
The switch design consists of a reservoir and float mechanism assembly that moves with
level changes in the day tank to actuate a micro switch which in turn controls alarms,
18
Enclosure
pumps, and valve operation to maintain an adequate fuel oil inventory in the day tank.
On June 11, 2007, CR 2007-17693 was written identifying a condition where the 1A
EDG day tank high level switch LS-59-007A failed to actuate on an increasing level
following maintenance activities. The licensee documented the cause of this failure to
be a manufacturing defect causing the switch to stick. The corrective action replaced
the switch with a new one. On October 22, 2008, CR 2008-32418 was written identifying
a condition where the 1A EDG day tank low level switch LS-59-008A failed to actuate on
a lowering level during the 24-hour run of the diesel. The licensee documented the
cause of this failure to be the float mechanism lever arm binding and not actuating the
micro switch. The corrective action replaced the switch with a new one. On February 9,
2009, CR 2009-3756 was written identifying a condition where the 1A EDG low level
switch LS-59-008A again failed to actuate on a lowering level, this time following online
maintenance activities. On February 16, 2009, CR 2009-4456 was written identifying a
condition where the 1B EDG low-low level switch LS-59-010B failed to actuate on a
lowering level following maintenance activities. Following this last failure, the licensee
acknowledged a trend and established a root cause team to evaluate the failures.
In the June 2007 failure, the 1A EDG day tank high level switch (LS-59-007A) failed and
the low level switch (LS-59-008A) was thought to have been sticking. The licensee
performed an apparent cause evaluation of sticking level switches and determined that
a manufacturing defect associated with the packing gland of the floats pivot shaft
caused some restricted movement. The licensee also determined that extended shelf
life contributed to the failures of these level switches. However, other than replacing the
switches with new ones, the only corrective action(s) that resulted from this evaluation
were to ensure that switches manufactured before 2000 were not used for plant
applications. In the October 2008 failure, the 1A EDG day tank low level switch (LS-59-
008A) failed during the 24-hour EDG run. Unit 1 was in a refuel outage at the time and
only one EDG was required to be operable in accordance with TS. The failed level
switch was sent out for a third-party evaluation but the immediate corrective action was
to replace with a new switch and perform an adequate post maintenance test. The third-
party evaluation subsequently came back indeterminate for root cause. In the February
2009 failure, the 1A EDG day tank low level switch (LS-59-008A) again failed following
maintenance activities and a week later the 1B EDG day tank low-low level switch (LS-
59-010B) failed following its maintenance. At the conclusion of this inspection period,
the licensee was completing a root cause evaluation for Murphy level switch failures.
Analysis. The finding was determined to be more than minor because it affected the
Mitigating Systems Cornerstone objective to ensure the availability, reliability, and
capacity of systems that respond to initiating events to prevent undesirable
consequences. The finding was evaluated in accordance with NRC Inspection Manual
Chapter 0609.04, Significance Determination Process (SDP) Phase 1 screening
worksheets. Because it represented an actual loss of the EDG system safety function of
a single train for greater than its Technical Specification (TS) allowed outage time, SDP
Phase 2 worksheets were evaluated. The finding was determined to be potentially
greater than Green because the 1A EDG was inoperable since June 2007 and no
operator recovery credit was allowed. An SDP Phase 3 analysis was performed for the
deficiency. The NRC's risk model was modified to increase the EDG failure rate on Unit
1 to reflect the decrease in reliability of the switches. The resulting analysis, including
19
Enclosure
the risk contribution due to external sources, was slightly less than 1E-6/year and the
finding is GREEN. The analysis showed the plant is very sensitive to changes in
reliability of the switches. Insights gained from the review of the performance deficiency
by the licensee resulted in recommended changes to the type of switches used, and
corrections to the alarm response procedure used to respond to fuel related diesel
issues. The inspectors determined that the cause of this finding was related to the
appropriate and timely corrective actions aspect of the corrective action program
component in the problem identification and resolution cross-cutting area (P.1 (d)).
Enforcement. Criterion XVI of 10 CFR 50, Appendix B, states in part, that Measures
shall be established to assure that conditions adverse to quality, such as failures,
malfunctions, deficiencies, deviations, defective material and equipment, and
nonconformances are promptly identified and corrected. Contrary to this requirement,
the licensee failed to take timely and effective corrective actions to prevent recurrence of
Unit 1 EDG day tank low level switch failures resulting in the 1A-EDG being inoperable
since 2007. Because the licensee entered the issue into their CAP as CR 2009-3756
and the finding is Green, this violation is being treated as a NCV, consistent with Section
VI.A of the NRC Enforcement Policy: NCV 05000335/2009002-02: Failure to Take
Timely and Effective Corrective Actions for EDG Day Tank Level Switch Failure.
4OA3 Event Follow-up
.1
(Closed) LER 05000389/2008-002-00, Unit 2 Manually Tripped As A Result of
Maintenance.
a.
Inspection Scope
The inspectors reviewed the root cause evaluation associated with LER 05000589/2008-
002-00 to determine whether a performance deficiency was involved, corrective actions
were adequate and to determine the safety significance. The inspectors also reviewed
the LER to verify its accuracy and completeness.
b.
Findings
Introduction. A Green self-revealing finding was identified for failure to implement
adequate process controls to minimize risk during maintenance on the Unit 2, 5B
feedwater heater high level limit switch which resulted in a manual reactor trip on
June 4, 2008. No violations of NRC requirements were identified because the feedwater
heater drain system is non-safety related.
Description. On June 4, 2008, Unit 2 was in Mode 1 at 100% power, while instrument
and control ( I &C) personnel were performing maintenance on the 5B Feedwater (FW)
Heater High Level Limit Switch LS-11-26B, when two taped energized leads were being
routed through a conduit elbow came in contact with the conduit and grounded. The
ground resulted in the 2B Heater Drain Pump being tripped on low level and the 2A Main
Feedwater Pump tripping on low suction pressure 50 seconds after the heater drain
pump tripped. The reactor was manually tripped in anticipation of a low steam generator
level auto-trip. All safe shutdown equipment operated as designed.
20
Enclosure
The licensee determined the root cause of the event was a failure to implement
adequate process controls to minimize risk during level switch replacement and drifting
of the pressure switch set point causing a premature actuation of the switch during a
feed water transient. Corrective actions included a development of specific procedural
direction for controlling energized leads during work evolutions using the risk
management process, design modifications to address vulnerability when performing
maintenance on level switches, and evaluation of industry best practices for training and
handling of energized leads.
Analysis. The inspectors determined that failure to implement adequate process controls
to minimize risk during maintenance on the Unit 2, 5B feedwater heater high level limit
switch resulting in a manual reactor trip was a performance deficiency. Specifically, the
licensee did not adequately plan work activities to minimize the risk of grounding the
energized leads. The existing plant processes for assessment of such risk are
contained in ADM 00110432, Control of Plant Work Orders and WW-AA-1000, Work
Activity Risk Assessment Process. Since the original work scope was to correct a steam
leak, the ADM 0010432, Red Sheet did not apply. The Red Sheet is a stand alone work
control checklist used by plant personnel to determine if proposed power block and
switchyard work activities have potential to cause an actuation of an Engineered
Safeguards Feature (EFS), plant transient or a unit trip. However, when the scope of the
work order was expanded to include the feedwater heater level switch replacement, the
package was not revised and a formal risk assessment was not performed.
The finding was more than minor because it resulted in a manual reactor trip. The
finding was associated with the human performance attribute and affected the Initiating
Events cornerstone objective of limiting the likelihood of those events that upset plant
stability and challenge critical safety functions during shutdown as well as at power
operations. Using the NRC Manual Chapter 0609, ASignificance Determination
Process,@ Attachment 609.04, Phase 1 screening worksheet, the finding was determined
to be of very low safety significance because it was a transient initiator but did not
increase the likelihood that mitigation equipment would not be available. The cause of
the finding is related to the cross-cutting area of Human Performance, with a work
control component. Specifically, the licensee did not adequately plan work activities to
minimize the risk of grounding the energized leads (H.3(a)).
Enforcement. No violation of NRC regulatory requirements occurred. The inspectors
determined that the finding did not represent a noncompliance because the performance
deficiency involved non-safety related equipment. This finding was determined to be of
very low safety significance (Green) and was entered into the corrective action program
as CR 2008-18858. This finding is identified as FIN 05000389/2009-02-04, Failure to
Implement Adequate Process Controls during Maintenance Activities Resulted in a
21
Enclosure
.2
(Closed) LER 05000389/2008-003-00: Unit 2 Condensate Pump Failure Resulting in
Manual Reactor Trip
The LER documented that while Unit 2 at 100 percent power, the 2B condensate pump
motor lead lugs overheated and melted due to high resistance at the lug crimp
connections which resulted in a manual reactor trip on June 7, 2008. The licensee
determined that the high resistance was caused by undetected epoxy resin in the motor
lead cables. The motor lead lugs were installed with undetected epoxy resin because a
vendor inadvertently impregnated the motor lead cables with epoxy resin during the
vacuum pressure impregnation (VIP) process. Corrective action included revising motor
rewinding specification to ensure that epoxy is not applied to the motor lead during the
vendors VIP process. The inspectors reviewed the LER and CR 2008-19114
documenting the event. The inspectors checked the accuracy and completeness of the
LER and the appropriateness of the licensees corrective actions. No findings of
significance or violations of NRC requirements were identified. This LER is closed.
4OA5 Other Activities
.1
Quarterly Resident Inspector Observation of Security Personnel and Activities
a.
Inspection Scope
During the inspection period the inspectors conducted observations of security force
personnel activities to ensure that the activities were consistent with the licensee
security procedures and regulatory requirements relating to nuclear plant security.
These observations took place during both normal and off-normal plant working hours.
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 reviews and inspection activities.
b.
Findings
No findings of significance were identified.
.2
(Closed) NRC Temporary Instruction (TI) 2525/175, Emergency Response Organization,
Drill/Exercise Performance Indicator, Program Review
The inspector completed Temporary Instruction TI 2515/175, Emergency Response
Organization, Drill/Exercise Performance Indicator, Program Review. Appropriate
documentation of the results was provided to NRC, HQ, as required by the TI.
This completes the Region II inspection requirements for this TI for St. Lucie Plant.
.3
(Closed) URI 05000335/2008005-02: Failure of the Automatic Diesel Fuel Oil Transfer
System Could Potentially Result in the 1A EDG Being Inoperable
During the fourth quarter of 2008, the inspectors selected CR 2008-32418, 1A EDG
Fuel Oil Transfer Pump Did Not Start When Required, for a more in depth review. An
22
Enclosure
URI was identified by the inspectors relating to past operability of the EDG, adequacy of
post maintenance testing, and the capability to manually operate the fuel oil transfer
system as necessary to maintain system design functions. This review was completed
by the licensee during this inspection period and further reviewed and evaluated by the
inspectors as discussed in more detail in section 4OA2.3 of this report. This URI was
documented in NRC Report No. 05000335, 335/2008005 dated January 30, 2009.
Introduction. The inspectors identified a Green non-cited violation (NCV) of TS 6.8.1.a
and Regulatory Guide (RG) 1.33, for the licensee failing to properly plan and specify an
adequate post maintenance test (PMT) as required by safety related administrative
procedure ADM-78.01, Post Maintenance Testing. Specifically, the inspectors
identified that the 1A EDG fuel oil day tank low level Murphy switch was not
demonstrated fully functional prior to returning the EDG to service following maintenance
which is in contrast to PMT completion criteria required by ADM-78.01.
Description. In October, 2008, while reviewing CR 2008-32418, 1A-EDG Fuel Oil
Transfer Pump Did Not Start When Required, the inspectors determined that during the
TS required 24-hour surveillance run of the 1A EDG performed on October 22, 2008, the
licensee had to mechanically agitate the day tank low level switch LS-59-008A for the
fuel oil transfer pump to automatically start. The day tank low level switch in designed to
start the transfer pump and begin refilling the day tanks automatically. Design Basis
Document section 7.14.1 states, in part, that the EDG day tanks shall be provided with
level switches to automatically operate the transfer pumps and the solenoid isolation
valves.
Upon further review of the licensees CAP program, the inspectors discovered that LS-
59-008A had failed previously during a routine calibration in June of 2007, and was
replaced under WO 37012672. When the inspectors reviewed WO 37012672, it was
determined that the specified PMT did not completely test the level switch functionality.
The only test performed on the level switch was a resistance measurement taken to
ensure the electrical contacts on the micro switch worked properly when it was manually
opened and closed with a thumb screw by the maintenance technician. The mechanical
float assembly was not tested to ensure it actuates in response to a lowering tank level
as designed during normal operation. The inspectors determined that if the float
mechanism was defective or not responding properly, the specified PMT would not
identify the new switch as unreliable or defective. The licensee documented this issue in
their CAP as CR 2008-32722 to ensured that prior to returning the 1A EDG to service,
the day tank low level switch would be demonstrated functional by lowering the actual
level in the day tank and testing the entire switch assembly including the float
mechanism.
Analysis. The inspectors determined that the licensees failure to perform an adequate
1A EDG day tank level switch PMT as required by procedure ADM-78.01was a
performance deficiency creating an inability to identify a degraded switch which could fail
to actuate on an actual lowering level in the tank and not being able to perform its design
function. The inspectors concluded that the finding was more than minor in accordance
with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition
Screening. The finding is associated with the equipment performance attribute of the
23
Enclosure
mitigating systems cornerstone. Using Manual Chapter 0609, Appendix A, Attachment
1, Significance Determination Process, Phase 1 Worksheet, the finding was
determined to have very low safety significance because it did not result in an actual loss
of a safety system function. The inspectors found that the cause of this finding was
related to the coordination of work activities aspect of the work controls component in
the human performance cross-cutting area (IMC 0305 aspect H.3.b).
Enforcement. TS 6.8.1.a requires that written procedures shall be established,
implemented, and maintained covering the activities specified in RG 1.33, Revision 2,
February 1978. RG 1.33, Appendix A, Item 9.a, requires maintenance that can affect
safety related equipment be properly preplanned and performed in accordance with
written instructions appropriate to the circumstances. Contrary to the above, PMT
requirements on the EDG fuel oil day tank low level switch were not adequately specified
and performed prior to returning the system to operable status in accordance with safety
related procedure ADM-78.01, Post Maintenance Testing. Because the failure to
implement the subject procedure was of very low safety significance and has been
entered in the licensees CAP, this violation is being treated as an NCV, consistent with
Section VI.A of the NRC Enforcement Policy: NCV 05000389/2009005-03, Failure to
Perform an Adequate Post Maintenance Test on the 1A-EDG Fuel Oil Day Tank Low
Level Switch.
3.
Closed) Temporary Instruction (TI) 2515/176, EDG TS Surveillance Requirements
Regarding Endurance and Margin Testing
a.
Inspection Scope
Inspection activities for TI 2515/176 were previously completed and documented in
inspection report 05000335, 389/2008004, and this TI is considered closed at St. Lucie
Nuclear Plant; however, TI 2515/176 will not expire until August 31, 2009. The
information gathered while completing this temporary instruction was forwarded to the
Office of Nuclear Reactor Regulation for review and evaluation.
b.
Inspection Findings
No findings of significance were identified.
4OA6 Exit
.1
Exit Meeting Summary
The resident inspectors presented the inspection results to Mr. Johnston and other
members of licensee management on April 2, 2009. The inspectors asked the licensee
whether any of the material examined during the inspection should be considered
proprietary information. The licensee did not identify any proprietary information.
24
Enclosure
.2
Annual Assessment Meeting Summary
On April 23, 2009, the Senior Resident Inspector met with Chris Costanzo and other
members of the licensee staff to discuss the NRCs annual assessment of the St. Lucie
Nuclear Plants safety performance for the period of January 1 through December 31,
2008. The annual assessment results were previously provided to Florida Power and
Light Company (FP&L) via letter dated March 4, 2009.
On April 29, 2009, the Chief of Reactor Projects Branch 3, the Resident Inspectors, and
Region II Public Affairs Officer held a Category 3 meeting for members of the public and
local officials. This Category 3 public meeting provided an open house public forum to
fully engage the public in a discussion of regulatory issues related to the NRCs ROP
and annual assessment of the St. Lucie Nuclear Plants safety performance for the
period January 1 through December 31, 2008. The presentation material used for
discussions and the list of attendees is available from the NRCs document system
(ADAMS) as accession number ML 090920483. ADAMS is accessible from the NRC
Web site at http://www/nrc.gov/reading-rm/adams.html (the Public Electronic Reading
Room).
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by the
licensee and is a violation of NRC requirements which meets the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCV.
Technical Specification 6.8.1 requires that written procedures be implemented
covering activities referenced in RG 1.33, Revision 2, February 1978. Contrary to
this, on November 11, 2008, maintenance workers removed blank flanges on RCP
seal injection piping with danger tags still attached. The finding was more than minor
because it could be viewed as a precursor to a significant event and if left
uncorrected could lead to a more significant safety concern in that if plant personnel
remove, breach, or otherwise touch, plant equipment with danger tags attached, it
could result in an injury, death, or other unwanted consequences. The finding was
determined to be of very low safety significance because it only affected the initiating
events cornerstone for a loss of coolant accident initiator and could not have resulted
in exceeding the TS limit for RCS leakage since the reactor was defueled. The
licensee entered this issue into their CAP as CR 2008-35071.
ATTACHMENT: SUPPPLEMENTAL INFORMATION
Attachment
KEY POINTS OF CONTACT
Licensee personnel:
C. Ali, Licensing Engineer
E. Belizar, Projects Manager
M. Bladek, Assistant Operations Manager
D. Calabrese, Emergency Preparedness Supervisor
D. Cecchett, Licensing Engineer
J. Connor, Engineering Manager - Programs
T. Cosgrove, Site Engineering Director
C. Costanzo, Plant General Manager
A. Day, Chemistry Manager
M. Delowery, Maintenance Manager
S. Duston, Training Manager
K. Frehafer, Licensing Engineer
J. Heinold, Chemistry Technical Supervisor
M. Hicks, Operations Manager
D. Huey, Acting Work Control Manager
G. Johnston, Site Vice President
J. Klauck, Assistant Operations Manger
J. Kramer, Site Safety Manager
R. McDaniel, Fire Protection Supervisor
M. Moore, Radiation Protection Manager
P. Paradis, Fix-It-Now Team Supervisor
T. Patterson, Performance Improvement Department Manager
J. Porter, Design Engineering Manager
G. Swider, Systems and Component Engineering Manager
NRC personnel:
M. Sykes, Region II, Chief, Branch 3, Division of Reactor Projects
S. Ninh, Region II, Senior Project Engineer, Branch 3, Division of Reactor Projects
R. Bernhard, Region II, Senior Risk Analyst, Division of Reactor Projects
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
NONE
Closed 05000335/2008005-02
Failure of the Automatic Diesel Fuel Oil Transfer
System Could Potentially Result in the 1A EDG Being
Inoperable (4OA5.3)
2
Attachment
05000389/2008-002-00
LER
Unit 2 Manually Tripped as a Result of Maintenance
Activities (4OA3.1)
05000389/2008-003-00
LER
Unit 2 Condensate Pump Failure Resulting in Manual Reactor Trip (4OA3.2)
2515/176
TI
EDG TS Surveillance Requirements Regarding
Endurance and Margin Testing (Section 4OA5.2)
Opened and Closed 05000335/2009002-01
Failure to Perform a Required TS Surveillance (1R22)05000335/2009002-02
Failure to Take Timely and Effective Corrective Actions
for EDG Day Tank Level Switch Failure (4OA2.3)05000335/2009002-03
Failure to Perform an Adequate Post Maintenance Test
on the 1A-EDG Fuel Oil Day Tank Low Level Switch
(4OA5.3)05000389/2009002-04
Failure to Implement Adequate Process Controls during
Maintenance Activities Resulted in a Manual Reactor Trip (4OA3.1)
LIST OF DOCUMENTS REVIEWED
Procedures
ADM-25.02, NRC Performance Indicators, Rev. 21A
ADM-04.02, Industrial Safety Program, Rev. 11A
ADM-78.01, Post Maintenance Testing, Rev. 30A
1-ARP-06-A16, Annunciator Response Procedure 1A EDG Panel, Revs. 1 & 2
1-OSP-59.11, Simultaneous Start of 1A EDG and 1B EDG Periodic Test, Rev. 1
2-OSP-59.11, Simultaneous Start of 2A EDG and 2B EDG Periodic Test, Rev. 4
1-OSP-59.01A, 1A EDG Monthly Surveillance
1-OSP-59.01B, 1B EDG Monthly Surveillance, Rev. 8A
2-OSP-59.01A, 2A EDG Monthly Surveillance, Rev. 9
2-OSP-59.05A, 2A EDG Air Start Check Valve Quarterly Test, Rev. 1
2-OSP-59.05B, 2B EDG Air Start Check Valve Quarterly Test, Rev. 1
1-OSP-69.14A, ESF - 18 Month Surveillance for EDG Start on SIAS Without LOOP & 24- Hour
Load Run - Train A
HPP-3, High Radiation Areas, Rev. 26A
2-0330020, Unit 2 Turbine Cooling Water System Normal Operation, Rev. 54
2-NOP-03.05, Aligning and Starting SDC Loop 2A, Rev. 40
EP-SR-102-1000, Nuclear Division Florida Alert and Notification System Guideline,
Rev. 0
06.80.02-E, Protection & Control Siren Maintenance Procedure, 01/11/2006
3
Attachment
06.80.01-I, Transmission and Substation Siren System Availability Test Procedure, Rev.
04/03/2008
NPSS-EP-WP-001, Public Alert Notification System Testing, Maintenance, and
Engineering, Rev. 2
EPG-06, Maintenance of the Emergency Recall System, Rev. 0
EPG-04, Drill and Exercise Program, Rev. 4
EPIP-13, Maintaining Emergency Preparedness Radiological Emergency Plan Training,
Rev. 19
EPG-03, Review and Revision of Emergency Preparedness Documents, Rev. 2
EPIP-01, Classification of Emergencies, Rev. 15 and16
EPIP-02, Duties and Responsibilities of the Emergency coordinator, Rev. 26 and 27
EPIP-06, Activation and Operation of the Emergency Operations Facility, Rev. 19 and 20
EPIP-08, Off-site Notifications and Protective Action Recommendations, Rev. 17, 18, 19,
and 19A
PI-AA-204, Condition Identification and Screening Process, Rev. 0
PI-AA-205, Condition Evaluation and Corrective Action, Rev. 0
EP-AA-100-1001, Guidelines for Maintaining Emergency Preparedness, Rev. 0
EP-AA-100-1002, Emergency Preparedness Change Review Committee Guideline,
Rev. 0
ADM-25.02, NRC Performance Indicators, Rev. 21B
EPG-01, Emergency Preparedness Assessment and Performance Monitoring, Rev. 4
Records, Calculations, and Data Reviewed
Work Order 35013863, L-29 Alarm and Power Supply Failure
Work Order 34004771, CEDS Power Supply Replacement
Work Order 37012672, Level Switch for Diesel Oil Day Tank 1A2 Low Level Control
Work Order 38024041, Level Switch for Diesel Oil Day Tank 1A2 Low Level Control
JPN-PSL-SEIP-93-049, EDG Instrument Setpoint Evaluation
PSL-1FSM-09-004, EDG Fuel Oil DOST Gravity Feed St. Lucie 1
Siren System Availability Test Records
Quarterly Siren Maintenance records: 1st and 3rd Quarters 2007
Quarterly Siren Maintenance records: 2nd and 4th Quarters 2008
Siren Extended (Annual) Maintenance records: 2008
St. Lucie Plant Emergency Response Directory, Rev. 51
Data packages for Pager Tests: 1st, 2nd, 3rd, and 4th Quarters 2008
First Quarter Training Drill package, February 15, 2007
Second Quarter Training Drill package, June 21, 2007
First Quarter Training Drill package, January 17, 2008
Second Quarter Training Drill package, April 23, 2008
Third Quarter Training Drill package, August 6, 2008
Fourth Quarter Training Drill package, December 10, 2008
Emergency Plan, Rev. 52, 53 and 54
Documentation of DEP opportunities: 1st, 2nd, 3rd, and 4th Quarters 2008
Drill and exercise participation records of ERO personnel, 1st, 2nd, 3rd, and 4th Quarters
2008
Siren testing data 1st, 2nd, 3rd, and 4th Quarters 2008
4
Attachment
Audits and Self-Assessments
PSL-08-07, Emergency Preparedness Functional Area Audit, August 12 - September 30,
2008
QSL-EP-07-08, Emergency Preparedness Functional Area Audit, August 6 - September
25, 2007
2008-31296, Self Assessment Quick Hit: 2008 EP Drill and Exercise Trends, October 10,
2008
2008-5397, Readiness Review for 2009 NEI 06-04 Hostile Action Based Drill Self-
Assessment, April 17 - September 30, 2008
2007-2668, Self Assessment Drill and Exercise Performance, January 02, 2007
Condition Reports
2008-6080
2008-22556
2008-32722
2008-33187
2009-0047
2009-0068
2009-0083
2009-0295
2009-0430
2009-0864
2009-1448
2009-1844
2009-1955
2009-1958
2009-1991
2009-2190
2009-3627
2009-4088
2009-7255
2009-9414
2007-17693
2008-26171
2008-31884
2008-324418
2009-2238
2009-2256
2009-2304
2009-2311
2009-2390
2009-2402
2009-2513
2009-2603
2009-3054
2009-3075
2009-3133
2009-3278
2009-3756
2009-3894
2009-3897
2009-3911
2007-1115
2007-14893
2007-17768
2007-20283
2007-38527
2009-4456
2009-4542
2009-4548
2009-4650
2009-4659
2009-4671
2009-4731
2009-4754
2009-4839
2009-4976
2009-4989
2009-5022
2009-5031
2009-5181
2009-5186
2007-18295
2007-18347
2007-38527
2008-5674
2008-34978
2009-4004
2009-4053
2009-5334
2009-5341
2009-5347
2009-5388
2009-5539
2009-5641
2009-5828
2009-6164
2009-6202
2009-6442
2009-6666
2009-6817
2009-6967
2007-18305
2007-18313
2008-7048
2008-13896
2008-26494
2008-31689
2009-5997
2009-6013
2009-6144
2009-7025
2009-7271
2009-7368
2009-7437
2009-7501
2009-7563
2009-7733
2009-8028
2009-8167
2009-8252
2009-8314
2009-8508
LIST OF ACRONYMS
Alert and Notification System (ANS) Testing
Emergency Response Organization Drill/Exercise Performance
Emergency Action Level
Emergency Response Organization
NEI
Nuclear Energy Institute
Performance Indicator
PS
Planning Standard
TI
Temporary Instruction