ML060270531
| ML060270531 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 01/27/2005 |
| From: | Casto C Division Reactor Projects II |
| To: | Stall J Florida Power & Light Co |
| References | |
| EA-06-027 IR-05-005 | |
| Download: ML060270531 (33) | |
See also: IR 05000250/2005005
Text
DOCUMENT TRANSMITTED HEREWITH CONTAINS SENSITIVE UNCLASSIFIED INFORMATION
WHEN SEPARATED FROM ATTACHMENTS 2 AND 3, THIS DOCUMENT IS DECONTROLLED
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
January 27, 2005
EA 06-027
Florida Power and Light Company
ATTN: Mr. J. A. Stall, Senior Vice President
Nuclear and Chief Nuclear Officer
P. O. Box 14000
Juno Beach, FL 33408-0420
SUBJECT:
TURKEY POINT NUCLEAR PLANT - INTEGRATED INSPECTION REPORT
05000250/2005005 AND 05000251/2005005; PRELIMINARY WHITE FINDING
Dear Mr. Stall:
On December 31, 2005, the US Nuclear Regulatory Commission (NRC) completed an
inspection at your Turkey Point Units 3 and 4. The enclosed integrated inspection report
documents the inspection findings which were discussed on January 12, 2006,
with Mr. W. Webster 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 letter and the enclosed supporting documentation discuss a finding that appears to have
low to moderate safety significance (White). This finding was assessed based on the best
available information, including influential assumptions, using the applicable Significance
Determination Process (SDP) and was preliminarily determined to be a White finding (i.e., a
finding with some increased importance to safety, which may require additional NRC
inspection).
This finding is characterized as an Apparent Violation (AV) of NRC requirements and is being
considered for escalated enforcement action in accordance with the NRC Enforcement Policy.
The current Enforcement Policy is included on the NRCs Web site at
http://www.nrc.gov/what-we-do/regulatory/enforcement/enforce-pol.html.
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
2
DOCUMENT TRANSMITTED HEREWITH CONTAINS SENSITIVE UNCLASSIFIED INFORMATION
WHEN SEPARATED FROM ATTACHMENTS 2 AND 3, THIS DOCUMENT IS DECONTROLLED
In this case, the B Auxiliary Feedwater Pump was inoperable due to an incorrectly installed
bearing since September 10, 2003, resulting in an apparent violation of Technical Specification 3.7.1.2. In addition, your staff apparently failed to identify and correct the condition of the pump
during this time period as required by 10 CFR 50 Appendix B, Criterion XVI, despite several
indicators that the pump was degraded.
As indicated in the enclosed SDP Phase II and III Risk Analysis, the issue appears to have a
low to moderate safety significance. The problem was discovered following a halted
surveillance test and was corrected by your staff prior to returning the pump to service.
Because you have already completed the necessary corrective actions the finding no longer
presents an immediate safety concern.
Before we make a final decision on this matter, we are providing you an opportunity (1) to
present to the NRC your perspectives on the facts and assumptions, used by the NRC to arrive
at the finding and its significance, at a Regulatory Conference or (2) submit your position on the
finding to the NRC in writing. If you request a Regulatory Conference, it should be held within
30 days of the receipt of this letter and we encourage you to submit supporting documentation
at least one week prior to the conference in an effort to make the conference more efficient and
effective. If a Regulatory Conference is held, it will be open for public observation and the NRC
will issue a press release to announce the conference. If you decide to submit only a written
response, such submittal should be sent to the NRC within 30 days of the receipt of this letter.
Please contact Mr. Joel T. Munday at (404) 562-4560 within seven days of the date of this letter
to notify the NRC of your intentions regarding the regulatory conference for the preliminary
White finding. If we have not heard from you within 10 days, we will continue with our
significance determination and associated enforcement processes on this finding, and you will
be advised by separate correspondence of the results of our deliberations on this matter.
Since the NRC has not made a final determination in this matter, no Notice of Violation is being
issued for the inspection finding at this time. Additionally, please be advised that the number
and characterization of the apparent violation may change as a result of further NRC review.
In addition, the enclosed report documents one NRC identified finding of very low safety
significance (Green). This finding was determined to involve a violation of NRC requirements.
Additionally, licensee identified violations, which were determined to be of very low safety
significance and are listed in Section 4OA7 of this report. However, because of the very low
safety significance of the issue, and because the issue was entered into your corrective action
program, the NRC is treating the issue as a Non-Cited violation (NCV) consistent with Section
VI.A of the NRC Enforcement Policy. If you wish to contest the NCV, 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-
001; 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 Turkey Point.
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
3
DOCUMENT TRANSMITTED HEREWITH CONTAINS SENSITIVE UNCLASSIFIED INFORMATION
WHEN SEPARATED FROM ATTACHMENTS 2 AND 3, THIS DOCUMENT IS DECONTROLLED
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter,
portions of 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). However, the NRC is continuing to review
the appropriate classification of the SDP Phase 2 Risk Analysis (Attachment 2) and SDP Phase
3 Risk Analysis (Attachment 3) within our records management program, considering changes
in our practices following the events of September 11, 2001. Using our interim guidance, the
attached analyses have been marked as Proprietary Information or Sensitive Information in
accordance with Section 2.390(d) of Title 10 of the Code of Federal Regulations and will not be
placed in the PDR. Please control the document accordingly (i.e., treat the document as if you
had determined that it contained trade secrets and commercial or financial information that you
considered privileged or confidential). We will inform you if the classification of these
documents change as a result of our ongoing assessments. ADAMS is accessible from the
NRC web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading
Room).
Sincerely,
/RA/
Charles A. Casto, Director
Division of Reactor Projects
Docket Nos. 50-250, 50-251
Enclosure: Inspection Report 05000250/2005005 and 05000251/2005005
w/Attachment: 1. Supplemental Information
2. Phase 2 SDP Risk Analysis (PROPRIETARY INFORMATION)
3. Phase 3 SDP Risk Analysis (PROPRIETARY INFORMATION)
cc w/encl: (See page 4)
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
4
DOCUMENT TRANSMITTED HEREWITH CONTAINS SENSITIVE UNCLASSIFIED INFORMATION
WHEN SEPARATED FROM ATTACHMENTS 2 AND 3, THIS DOCUMENT IS DECONTROLLED
cc w/encl:
T. O. Jones
Site Vice President
Turkey Point Nuclear Plant
Florida Power and Light Company
9760 SW 344th Street
Florida City, FL 33035
Walter Parker
Licensing Manager
Turkey Point Nuclear Plant
Florida Power and Light Company
9760 SW 344th Street
Florida City, FL 33035
Michael O. Pearce
Plant General Manager
Turkey Point Nuclear Plant
Florida Power and Light Company
9760 SW 344th Street
Florida City, FL 33035
Mark Warner, Vice President
Nuclear Operations Support
Florida Power & Light Company
P. O. Box 14000
Juno Beach, FL 33408-0420
Rajiv S. Kundalkar
Vice President - Nuclear Engineering
Florida Power & Light Company
P. O. Box 14000
Juno Beach, FL 33408-0420
M. S. Ross, Managing Attorney
Florida Power & Light
P. O. Box 14000
Juno Beach, FL 33408-0420
Distribution: (See page 5)
_________________________
OFFICE
RII:DRP
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RII:DRS
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RII:ORA
SIGNATURE
JSS1 by email
TCK
RJR1
SON
MXM3
WGR1
NAME
SStewart:rcm
TKolb
RReyes
SNinh
MMaymi
WRogers
DATE
1/26/06
1/26/06
1/26/06
1/23/06
1/23/06
1/ /2006
1/27/06
E-MAIL COPY?
YES
NO YES
NO YES
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NO
OFFICE
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SIGNATURE
RLM
SES
NAME
RMoore
SSparks
DATE
1/27/06
1/27/06
1/ /2006
1/ /2006
1/ /2006
1/ /2006
1/ /2006
E-MAIL COPY?
YES
NO YES
NO YES
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NO
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-250, 50-251
License Nos:
Report No:
05000250/2005005, 05000251/2005005
Licensee:
Florida Power & Light Company (FP&L)
Facility:
Turkey Point Nuclear Plant, Units 3 & 4
Location:
9760 S. W. 344th Street
Florida City, FL 33035
Dates:
October 1, 2005 - December 31, 2005
Inspectors:
S. Stewart, Senior Resident Inspector
T. Kolb, Resident Inspector
M. Maymi, Reactor Engineer (1RO15)
R. Aiello, Senior Examiner (1RO1)
R. Reyes, Resident Inspector, Crystal River 3 (1RO23)
R. Moore, Senior Reactor Inspector (4OA5)
S. Ninh, Senior Project Engineer
Approved by:
Joel T. Munday, Chief
Reactor Projects Branch 3
Division of Reactor Projects
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
Enclosure
SUMMARY OF FINDINGS
IR 05000250/2005-005, 05000251/2005-005; 10/01/2005 - 12/31/2005; Turkey Point Nuclear
Power Plant, Units 3 and 4; Problem Identification and Resolution.
The report covered a three month period of inspection by resident inspectors, a region based
reactor engineer and senior examiner, and a region based senior project engineer. One Green
finding, which was a non-cited violation (NCV), and one Preliminary White Finding, which was
an apparent violation (AV), were identified. 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,
Revision 3, dated July 2000.
A
Inspector Identified & Self-Revealing Findings
Cornerstone: Mitigating Systems
Green: The inspectors identified a Non-Cited Violation of 10 CFR 50, Appendix
B, Criterion XVI, Corrective Action, for failure of the licensee to correct a
repeated condition adverse to quality, that being problems with operators
adjustment of auxiliary feedwater speed control.
The finding was more than minor and affected the Mitigating Systems
cornerstone because the licensee failed to correct a longstanding problem with
manual setting of the auxiliary feedwater speed control knob resulting in
repeated inoperabilities. The finding was determined to be of very low safety
significance because no instances of loss of function or periods of sustained
inoperability beyond technical specification limitations were identified. The
finding affects the cross cutting area of Problem Identification and Resolution
due to the failure to resolve a known condition adverse to quality related to the
problems with manual setting of auxiliary feedwater speed control. (4OA2.2)
TBD. An Apparent Violation (AV) of Technical Specification 3.7.1.2 was
identified for an inoperable auxiliary feedwater pump with a contributing violation
of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action" for failure of
the licensee to promptly identify and correct a significant condition adverse to
quality affecting the "B" turbine driven auxiliary feedwater (TDAFW) pump.
Specifically, the "B" TDAFW pump exhibited high vibration during routine
inservice tests following the replacement of the pump inboard journal bearing in
September 2003. Periodic oil samples taken since 2003 were also abnormal
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
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ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
Enclosure
and on occasion, the bearing was reported to have high temperature. Plant staff
were aware of the continued high vibration but did not declare the pump
inoperable and take corrective action. Subsequently, on November 7, 2005, a
test of the "B" TDAFW pump was halted due to increasing vibrationsabove the
inservice testing limit. The increased vibration was later determined by the
licensee to be directly related to the pump inboard journal bearing that was
installed incorrectly on September 10, 2003. The licensee entered this issue in
the Corrective Action Program as condition report (CR) 2005-30750. (4OA3.3)
The finding was determined to be more than minor because the "B" TDAFW
pump which is shared between Unit 3 and Unit 4, was inoperable more than 30
days. The Mitigating Systems Cornerstone objective to ensure the availability,
reliability, and capacity of systems that respond to initiating events to prevent
undesirable consequences was affected by the finding. NRC Phase 1 and
Phase 2 Significance Determination Process (SDP) analyses determined that
this finding is potentially greater than Green because the "B" TDAFW pump was
inoperable greater than 30 days and no operator recovery credit was identified.
An SDP Phase 3 analysis was performed and concluded the issue was of low to
moderate safety significance, White. This finding is also related to the
cross-cutting area of problem identification and resolution due to the failure to
promptly resolve a known condition adverse to quality. (4OA3)
B.
Licensee Identified Violations
Four violations of very low safety significance, which were identified by the licensee,
have been reviewed by the inspectors. Corrective actions taken or planned by the
licensee have been entered in the licensees corrective action program. The violations
and corrective actions are listed in Section 4OA7 of this report.
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
Enclosure
REPORT DETAILS
Summary of Plant Status:
Unit 3 began the period at full rated thermal power and operated at or near full power for the
inspection period except for the following: Unit 3 tripped on October 15 due to a feedwater
transient that started when a flow transmitter failed. The unit was restarted and returned to
Mode 1 on October 19, but remained at reduced power due to failure of the 3B main feedwater
pump. On October 24, Unit 3 was shutdown to Mode 3 because of grid instabilities due to
Hurricane Wilma. The unit was returned to power operations on October 27. Following repair
of the 3B main feedwater pump, Unit 3 returned to full power operation on November 2. On
December 20, the unit was reduced to 60 percent power to repair minor leakage in the main
condenser. The leak was repaired and the unit was returned to full power on December 22,
2005. On December 29, Unit 3 was shutdown to repair a small cooling water leak in the main
generator exciter. The leak was repaired and the unit returned to power operation on
December 31.
Unit 4 began the period at full rated thermal power and operated at or near full power for the
inspection period except for the following: Unit 4 was shutdown to Mode 3 on October 24
because of grid instabilities due to Hurricane Wilma. Subsequently, Unit 4 remained shutdown
due to secondary chemistry problems. On October 31, switchyard insulator salting caused loss
of the Unit 4 startup transformer and on November 1, the unit was placed in Mode 5. Following
restoration of offsite power and resolution of chemistry problems, the unit was restarted on
November 12 and returned to full power operation on November 14.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01
Adverse Weather Protection
.1
Impending Adverse Weather: Hurricane Wilma
a.
Inspection Scope
During the preparations and onset of Hurricane Wilma on October 23, 2005, the
inspectors verified the status of licensee actions in accordance with off-normal
procedure 0-ONOP-103.3, Severe Weather Preparations, and 0-EPIP-20106, Natural
Emergencies. This verification included physical walkdowns of the portions of the plant
protected area, control room observations, and discussions with responsible licensee
personnel regarding preparations of systems and personnel for high winds and potential
flooding. The inspectors specifically examined the following areas:
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
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Enclosure
Plant Intake area
Standby steam generator feedwater pump area
Prior to onset of the storm, regional specialists were dispatched to remain onsite and
monitor licensee activities during the storm. The specialists monitored the Unusual
Event declaration, dual unit shutdown, and storm mitigation, maintaining
communications with NRC Region II. Control room indications and licensee response to
severe weather were specifically observed as the storm passed. After the storm,
resident inspectors returned to the site to monitor recovery activities.
b.
Findings
No findings of significance were identified. Vital safety systems were not affected by the
storm.
1R04
Equipment Alignment
1.
Partial Equipment Walkdowns
a.
Inspection Scope
The inspectors conducted three partial alignment verifications of the safety-related
systems listed below. These inspections included reviews of the operability of a train of
safety systems using plant lineup procedures, operating procedures, and piping and
instrumentation drawings. The specified configurations were compared with observed
equipment configurations to verify that the critical portions of the operable systems were
correctly aligned.
Unit 3, Charging and Letdown, in accordance with licensee procedure 3-OP-047,
CVCS - Charging and Letdown, ECO 3-05-10-025 regarding the charging pump
discharge flow element, and drawing 5613-M-3047, sh. 2
Both Units 4160 volt electrical distribution on October 28 during plant recovery
from dual unit shutdown using licensee electrical diagram 5610-T-E-1591
Unit 3 auxiliary feedwater trains 1 and 2 when B auxiliary feedwater pump was
out of service due to high bearing vibrations
b.
Findings
No findings of significance were identified.
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Enclosure
.2
Complete System Walkdown
a.
Inspection Scope
The inspectors conducted one detailed walkdown/review of the alignment and condition
of the Unit 4 Residual Heat Removal (RHR) system, which included both A and B RHR
pumps and heat exchangers. The inspectors utilized licensee procedure 4-OP-050,
Residual Heat Removal System, and drawing 5614-M-3050 (Residual Heat Removal
System), as well as other licensing and design documents to verify that the system
alignment was correct. During the walkdown, the inspectors verified that: valves and
pumps were correctly aligned and did not exhibit leakage that would impact their
function; that major portions of the system and components were correctly labeled; that
selected hangers and supports were installed and functional; valves important to safety
were locked as required by plant drawings and procedures; and that electrical support
systems were properly aligned. A review of open corrective action reports and
maintenance work requests using the system health report was also performed to verify
that the licensee had appropriately characterized and prioritized equipment problems for
resolution in the corrective action program. In addition, the inspectors reviewed the
Updated Final Safety Analysis Report to check the ability of the system to perform its
design function.
b.
Findings
No findings of significance were identified.
1R05
Fire Protection
.1
Fire Area Walkdowns
a.
Inspection Scope
The inspectors toured the following nine plant areas to evaluate control of transient
combustibles and ignition sources. The inspectors also checked 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 0-ADM-016, Fire Protection Plan, and 10 CFR Part 50,
Appendix R. The licensees fire impairment lists, updated on a daily basis were routinely
reviewed. In addition, the inspectors reviewed the condition report database to verify
that fire protection problems were being identified and appropriately resolved. The
following areas were inspected:
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Enclosure
Unit 4 West Electrical Penetration Room
Unit 3 South Electrical Penetration Room
Unit 4 Residual Heat Removal Room
Unit 3A and 3B 4160 Switchgear Rooms
Unit 3 Refuel Floor
Unit 4 Emergency Diesel Generator Building
Unit 3 Emergency Diesel Generator Building
Main Control Room
Unit 3 Charging Pump Room
b.
Findings
No findings of significance were identified.
1R07
Heat Sink Performance
a.
Inspection Scope
The inspectors observed activities in accordance with procedures 4-OSP-019.4, Unit 4
Component Cooling Water Heat Exchanger Performance Monitoring, and procedure
0-PMM-030.1, Component Cooling Water Heat Exchanger Cleaning, on December 21,
2005. The inspectors periodically checked the licensee monitoring of intake
temperature versus system temperature limits to assure technical specification
requirements were met and assessed the operational readiness of the cooling systems
should they be needed for accident mitigation. The inspectors verified that the licensee
conducted appropriate preventive maintenance to assure system readiness.
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification Program
a.
Inspection Scope
On November 21, 2005, the inspectors observed and assessed licensed operator
actions to a simulated set of transients and operating events done in the licensees plant
specific simulator. The licensee conducted Simulator Evaluated Scenario 750203100,
which included a loss of 3P08 (3B Inverter), a trip of the 3A steam generator feedwater
pump resulting in a runback, pressurizer safety valve 3-551C leakage, and a reactor trip
and safety injection with failure of MOV 3-843 A/B valves to open, along with a failure of
the turbine to trip. The inspectors observed the operators use of Emergency Operating
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Enclosure
Procedure (EOP) E-0, Reactor Trip or Safety Injection; EOP E-1, Loss of Reactor or
Secondary Coolant; and off-normal procedures, 3-ONOP-008, Loss of 120V Vital
Instrument Panel 3P08, and 3-ONOP-089, Turbine Runback. The operators actions
were checked to be in accordance with licensee procedures. Event classifications
(including Site Area Emergency) were checked for proper classification and prompt
state notification. The simulator board configurations were compared with actual plant
control board configurations concerning recent plant modifications. The inspectors
specifically evaluated the following attributes related to operating crew 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
Oversight and direction provided by Operations supervision, including ability to
identify and implement appropriate Technical Specification actions, regulatory
reporting requirements, and emergency plan actions and notifications
b.
Findings
No findings of significance were identified.
1R12
Maintenance Effectiveness
a.
Inspection Scope
The inspectors reviewed the following equipment problems and associated condition
reports 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 Administrative Procedure 0-ADM-728, Maintenance Rule Implementation.
The inspectors efforts focused on maintenance rule scoping, characterization of
maintenance problems and failed components, risk significance, determination of (a)(1)
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 checked
that when operator actions were credited to prevent failures, the operator was dedicated
at the location needed to accomplish the action in a timely manner, and that the action
was governed by applicable procedures. Furthermore, the inspectors verified that
equipment problems were being identified and entered into the corrective action
program.
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Enclosure
Work Order 35019306-01, Replace CR 2940 switches on breaker 4P210A for 4A
residual heat removal pump and associated CR 2005-21545 for extended
unavailability due to clearance problem
CR 2005-29696, Unusual Event due to loss of Unit 4 startup transformer
CR 2005-28117, Failure of Unit 3 feedwater regulating valve FCV-3-498
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 and control room inspections of the
licensees risk assessment of seven emergent or planned maintenance activities. The
inspectors compared the licensees risk assessment and risk management activities
against 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
Procedures 0-ADM-068, Work Week Management and O-ADM-225, On Line Risk
Assessment and Management. The inspectors also reviewed the effectiveness of the
licensees contingency actions to mitigate increased risk resulting from the degraded
equipment. The inspectors evaluated the following risk assessments during the
inspection:
Unit 4, October 26, 2005, Risk Condition Yellow for motor inspections on intake
cooling water (ICW) and component cooling water (CCW) pumps
Unit 3, October 17, 2005, Risk Condition Orange for isolation of the charging
header for weld leak repair to flow transmitter FT-3-122
Unit 4, Mode 3 operations when draining the condensate and feedwater systems
for chemistry control using licensee procedure 0-ADM-051, Outage Risk
Assessment and Control
Unit 3, November 8, 2005, power operations while testing 4B emergency diesel
generator, conducting switchyard work, and removing auxiliary feedwater pump
B from service due to high vibrations
Unit 3, December 2, 2005, replacement of 3C steam generator steam flow switch
Unit 3 and 4, December 15, 2005, operations during maintenance associated
with the A auxiliary feedwater pump
Unit 4, December 17, 2005, startup transformer removed from service earlier
than expected for switchyard insulator cleaning, CR 2005-34862
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Enclosure
b.
Findings
No findings of significance were identified.
1R14
Personnel Performance During Non-routine Plant Evolutions
a.
Inspection Scope
For the six non-routine events described below, the inspectors either observed the
activity or reviewed operator logs and computer data to determine that the evolution was
conducted safely and in accordance with plant procedures. Specific checks were done
to assess operator preparedness and performance in coping with non-routine events
and transients.
Unit 3 reactor trip and operator response on October 15, 2005
Unit 3 startup and return to power operations on October 19, 2005
Unusual Event declaration (October 23) and subsequent dual unit shutdown due
to onset of Hurricane Wilma on October 24, 2005
Return of Unit 3 to power operation on October 27, 2005
Unusual Event declaration on October 31, 2005 due to loss of Unit 4 startup
transformer
Return of Unit 4 to power operation on November 12, 2005
b.
Findings
No findings of significance were identified.
1R15
Operability Evaluations
a.
Inspection Scope
The inspectors reviewed six interim disposition and operability determinations
associated with the following condition reports to ensure that Technical Specification
operability was properly supported and the system, structure, or component remained
available to perform its safety function with no unrecognized increase in risk. The
inspectors reviewed the updated Final Safety Analysis Report (FSAR), applicable
supporting documents and procedures, and interviewed plant personnel to assess the
adequacy of the interim condition report disposition.
Unit 4 CR 2005-27461 Intake cooling water pump flange and baseplate corrosion
Unit 4 CR 2005-29846 Pressurizer maximum spray water temperature
differential exceeded. The inspectors reviewed the Technical Specification
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Enclosure
3.4.9.2 and Bases, and ASME Boiler and Pressure Vessel Code,Section III
Unit 4 CR 2005-32226 4A EDG voltage regulator operating erratically
Unit 3 CR 2005-28863 3B2 Battery Charger amps found low during performance
of 0-SME-003.7, 125 VDC Station Battery Weekly Maintenance
Unit 3 CR 2005-33226 3A Charging Pump Bolting 35029213
Unit 3 and 4 CR 2005-34288 3A High Head Safety Injection pump high motor
vibrations
b.
Findings
No findings of significance were identified.
1R16
Operator Work Around
.1
Cumulative Effects
f.
Inspection Scope
The inspectors reviewed the cumulative effects of the operator workarounds that were in
place on December 1, 2005, to verify that those effects could not increase an initiating
event frequency, affect multiple mitigating systems, or affect the ability of operators to
properly respond to plant transients and accidents. The following workarounds were
reviewed:
Unit 4 #3 Control Valve Oscillations
Unit 4 HCV-4-758 and FCV-4-605 leaking during residual heat removal
Unit 4 MOV 4-1409 and FCV 4-498 leaking affecting 4C steam generator level
b.
Findings
No findings of significance were identified.
.2
Selected Operator Work Around
a.
Inspection Scope
The inspectors reviewed the following Operator Work Around (OWA), to verify that this
work around did not affect either the functional capability of the related system in
responding to an initiating event, or the operators ability to implement abnormal or
emergency operating procedures.
Unit 4 MOV 4-1409 and FCV 4-498 leaking by affecting 4C S/G level (CR 2005-
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31969 and CR 2005-31990)
b.
Findings
No findings of significance were identified.
1R17
Permanent Plant Modification
4.
Inspection Scope
The inspectors reviewed the documentation for the following Plant Change and
Modifications (PC/M) associated with Unit 3 and 4:
C
PC/M 03-048 (June 8, 2004) to remove the Unit 3 Turbine Runback function
upon receipt of an Overpower or Overtemperature Delta-T signal
C
PC/M 05-059 (May 10, 2005) to replace Unit 4 Core Exit Thermocouples via In-
core System Flux Thimbles at location H1 and M3
The inspectors reviewed the 10 CFR 50.59 screening and evaluation, fire protection
review, environmental review, alara screening, and license renewal review. The
inspectors reviewed all associated plant drawings and updated Final Safety Analysis
Report documents impacted by these PC/Ms and discussed the changes with plant
staff.
b.
Findings
No findings of significance were identified.
1R19
Post Maintenance Testing
a.
Inspection Scope
For the six post maintenance tests 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 0-ADM-737, Post
Maintenance Testing, were incorporated into test requirements. The inspectors
reviewed the following work orders (WO) and/or surveillance procedures (OSP):
C
Unit 3 and 4, post maintenance testing conducted on October 6, 2005 on the A
auxiliary feedwater pump replacement in accordance with work order 33021678-
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01, 0-OSP-075.11, Auxiliary Feedwater Inservice Test, and 0-ADM-737, Post
Maintenance Testing
C
Unit 4, post maintenance testing conducted on November 11, 2005 for the C
intake cooling water (ICW) check valve replacement in accordance with work order 35006946-01 and 0-ADM-737
C
Unit 3 and 4, post maintenance testing conducted on November 11, 2005 on the
B auxiliary feedwater pump in accordance with work order 35008593-01
C
Unit 3, post maintenance testing conducted on December 2, 2005, for the 3A
charging pump speed controller and packing replacement per work order 35029213 and work order 35029206
C
Unit 4, post maintenance testing conducted on December 20, 2005, for thermal
overload calibration per 0-PME-102.3, MOV Thermal Overload Protection Test
and Calibration, in accordance with work order 35012168 for MOV 4-1405,
Auxiliary Feedwater Pumps Steam Supply valve
Unit 4, post maintenance testing conducted on December 23, 1999 for the 4B
safety related 125 VDC battery per work order 99002831-01, which included the
performance of 0-SMF-003.15, Station Battery 60 Month Maintenance
b.
Findings
No findings of significance were identified.
1R20
Unit 4 Outage Activities
During Mode 4 and 5 operations on Unit 4, the inspectors evaluated activities as
described below, to verify the licensee considered risk in developing schedules, adhered
to administrative risk reduction methodologies, and adhered to operating license and
Technical Specification requirements that maintained defense-in-depth.
.1
Shutdown Activities
a.
Inspection Scope
The inspectors observed or reviewed portions of the Unit 4 cooldown to verify that
Technical Specification cooldown restrictions were followed.
b.
Findings
No findings of significance were identified. A licensee identified issue is documented in
4OA7 of this report.
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.2
Licensee Control of Outage Activities
a.
Inspection Scope
During the outage, the inspectors observed the items or activities described below, to
verify that the licensee maintained defense-in-depth commensurate with the outage risk-
control plan for key safety functions and applicable Technical Specifications when taking
equipment out of service.
Electrical Power
The inspectors also reviewed the licensees responses to emergent work and
unexpected conditions, to verify that control-room operators were cognizant of the plant
configuration.
b.
Findings
No findings of significance were identified. A licensee identified issue is documented in
4OA7 of this report.
.3
Monitoring of Heatup and Startup Activities
a.
Inspection Scope
The inspectors reviewed activities during reactor restart and power escalation to verify
that reactor parameters were within safety limits and that the startup evolutions were
done in accordance with pre-approved procedures and plans.
b.
Findings
No findings of significance were identified.
1R22
Surveillance Testing
a.
Inspection Scope
The inspectors either reviewed or witnessed the following three surveillance tests to
verify that the tests met the Technical Specifications, 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
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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 inservice test
(IST) and one leakrate determination.
3-OSP-023.1, Diesel Generator Operability Test conducted on October 20, 2005
4-OSP-050.2, Residual Heat Removal System Inservice Test conducted on
November 20, 2005. This was an IST surveillance
4-OSP-41.1, Reactor Coolant System Leakrate Calculation
b.
Findings
No findings of significance were identified.
1R23
Temporary Plant Modifications
a.
Inspection Scope
The inspectors reviewed the five temporary modifications listed below to ensure that the
modification did not adversely affect the operation of the system. The inspectors
screened temporary plant modifications for systems that were ranked high in risk for
departures from design basis and for inadvertent changes that could challenge the
systems to fulfill their safety function. On closed temporary modifications, the inspectors
verified that appropriate post maintenance testing had been completed after the
modification had been removed and the system restored to normal. Condition reports,
CR 2005-23433 and 2005-23486, and FPL Quality Assurance Audit QAO-PTN-05-04,
Configuration Management were reviewed by the inspectors. The inspectors conducted
plant tours and discussed system status with engineering and operations personnel to
check for the existence of temporary modifications that had not been appropriately
identified and evaluated.
TSA 3-04-013-029
Temporary power to the 3CD Diesel Instrument Air
Compressor jacket water heater, heat tracing and battery
charger
TSA 3-05-075-012
Lift power leads to the A Auxiliary Feed Water Pump
turbine lube oil temperature controller TC-6537A
TSA 3-05-041-001
Increase annunciator F 1/1, RCP Motor / Shaft High
Vibration, input from 3C RCP Bently Navada Shaft
Vibration vertical and horizontal monitors alarm setpoint
from 5.0 mils to 9.0 mils
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TSA 4-05-074-023
Lift wires on FT-4-476 loop to prevent injection of noise,
and all bi-stables within channel IV protection Loops to be
reset
TSA 4-05-013-017
Provide temporary power, via a Power Panel fed from
Mcgreggor substation, for the 4CD Instrument Air
Compressor
b.
Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness (EP)
1EP6 Drill Evaluation
Inspection Scope
On December 6, 2005 the inspectors observed the licensee simulator based emergency
preparedness drill. Results of the drill are used by the licensee as inputs into the
Drill/Exercise Performance and Emergency Response Organization Drill Participation
Performance Indicators. The drill involved an unusual event declaration for loss of all
plant annunciators for greater than 15 minutes, and an Alert declaration for a simulated
fire that affected safety equipment, including intake cooling water pumps. The
inspectors observed the licensees event classification in accordance with licensee
procedure 0-EPIP-20101, Duties of the Emergency Coordinator. Notification of the
state warning point of the simulated events was also observed. At the conclusion of the
drill, the inspectors discussed the drill with plant staff and noted that drill improvement
items were documented in the corrective actions program.
b.
Findings
No findings of significance were identified.
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4.
OTHER ACTIVITIES
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 corrective action program. This review was accomplished by reviewing daily
printed summaries of condition reports and by reviewing the licensees electronic
condition report database. Additionally, the 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 Review
a.
Inspection Scope
The inspectors selected two condition reports identified below for a detailed review and
discussion with the licensee. The condition reports describe circumstances in which the
auxiliary feedwater pump governor speed control knobs were improperly operated
resulting in a degraded auxiliary feedwater capability. In multiple cases, the speed
control knob became loose and disengaged. In the most recent case, the knob was
improperly set following testing, causing a train of auxiliary feedwater protection to be
degraded/inoperable for about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The condition reports were reviewed to ensure
that an appropriate evaluation was performed and appropriate corrective actions were
specified and prioritized. Other attributes checked included disposition of operability,
resolution of the problem including cause determination and corrective actions. The
inspectors evaluated the condition reports in accordance with the requirements of the
licensees corrective actions process as specified in NAP-204, Condition Reporting.
Additional condition reports reviewed included CR 2005-33569, C auxiliary feedwater
pump inoperable (B and C AFW pump control knobs in the minimum position); CR
2005-8073, C auxiliary feedwater pump governor knob (became loose and disengaged);
and CR 2003-1453, B auxiliary feedwater pump governor speed control knob found free
to turn.
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CR 2005-18866, C Auxiliary Feedwater governor Adjust Knob Fell Off
CR 2005-33550, Failure of C Auxiliary Feedwater Pump to reach 5900 rpm when
started
b.
Findings
Introduction: The inspectors identified a Green Non-Cited Violation of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Action, for failure of FPL to assure that a
condition adverse to quality, involving a repeat problem with manual mis-operation of
auxiliary feedwater pump speed control, was promptly corrected.
Description: During surveillance testing on December 5, 2005, the C turbine driven
auxiliary feedwater pump failed to achieve the specified 5900 rpm, when started and
only reached a maximum speed of 1000 rpm. The failed test was caused by improper
setting by operators of the speed control knob during testing earlier that day. After the
test, the licensee found the B auxiliary feedwater pump governor control switch was also
improperly set, again due to operators and earlier testing on the same day. The
inspector had observed that this speed control knob had fallen off during manual over-
adjustment on repeated occasions: June 27, 2005, following an auxiliary feedwater
actuation associated with a reactor trip; and March 18, 2005, during recovery from
testing. Problems with control of the auxiliary feedwater turbine speed control was a
long standing issue, documented in 2003 when the B pump knob was found free to
rotate because manual mis-operation following testing caused a loose ring assembly,
and earlier problems discussed in NRC Information Notice 86-14, PWR Auxiliary
Feedwater Pump Turbine Control Problems. Other than reconnecting the knob, no
corrective actions from the earlier events were implemented to assure that manual
manipulation of the switch did not result in a degraded auxiliary feedwater system.
During periods when the speed control knob(s) were out of position, there was an
increased plant risk because the affected pump(s) would not have accomplished their
safety function.
Analysis: The licensees failure to correct repeated problems with the same root cause,
that being mis-operation of the auxiliary feedwater pump speed control knob, affecting
multiple pumps and resulting in recurring pump inoperability, was a performance
deficiency. The finding was more than minor because it affected the Mitigating System
cornerstone objective of ensuring the reliability of systems that respond to initiating
events to prevent undesirable consequences (i.e. loss of heat sink). The finding was
screened using NRC Manual Chapter 0609, Appendix A, Attachment 1, Significance
Determination Process Screening Worksheet. The Mitigating Systems cornerstone was
affected and because the inoperabilities in each case were limited to one pump or train
and were of short duration (less than the technical specification action requirements),
the finding screened as Green. In all cases reviewed by the inspectors, the redundant
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train remained available when the mis-operation occurred and no loss of function was
identified. No Phase 2 assessment was required because the inoperabilities were less
than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in duration and external events were not required to be analyzed. The
finding affects the cross cutting area of Problem Identification and Resolution due to the
repeated failure to correct/resolve a known condition adverse to quality.
Enforcement: 10 CFR 50. Appendix B, Criterion XVI, requires, in part, that for significant
conditions adverse to quality, measures shall assure that corrective action is taken to
preclude repetition. Contrary to the above, after repeated problems with assuring
proper speed control for the auxiliary feedwater pump turbines, on March 18, 2005 and
June 27, 2005, and prior occasions, measures were not adequate to prevent repetition
on December 5, 2005, when the speed controls for the B and C auxiliary feedwater
pumps were improperly positioned by an operator. On the earlier occasions, the control
knob either fell off due to manual mis-operation by operators, or was found free-
wheeling due to failure of the friction device caused by manual mis-operation. When
identified, the licensee restored the knob to its correct position and documented the
problem in the corrective actions program as CR 2005-33550 and CR 2005-33569. The
violation existed during periods when the licensee did not assure that the speed control
knob was properly set. Not all manipulations of the speed control resulted in equipment
inoperabilities, and in no case was a loss of function identified. Because the finding is of
very low safety significance, Green, and had been entered into the corrective action
program, the violation is being treated as a Non-Cited violation consistent with Section
VI.A.1 of the NRC Enforcement Policy: NCV 50-250/2005-005-02 and 50-251/2005-005-
01, Failure to Correct Repeated Problems with Auxiliary Feedwater Pump Manual
Speed Control.
.3
Semi-Annual Trend Review
Inspection Scope
As required by Inspection Procedure 71152, Identification and Resolution of Problems,
the inspectors reviewed the licensees corrective action program and associated
documents to identify trends that could indicate the existence of a more significant
safety issue. The inspectors review was focused on repetitive equipment issues, but
also considered the results of daily inspector corrective actions 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 June 2005 through December 2005. The review also included issues
documented outside the normal CAP in Chief Nuclear Officers Indicator Report, dated
November 14, 2005. Corrective actions associated with a sample of the issues
identified in the licensees corrective actions program were reviewed for adequacy.
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Assessment and Observations
No findings of significance were identified. However, the inspectors, in reviewing
licensee performance over the last six months, noted a number of occasions when
licensee personnel missed surveillance intervals that are in place to assure equipment
reliability such that margins of safety are maintained. On November 3, 2005, the
inspectors identified that the licensee missed technical specification surveillance
4.8.1.1.2.c, for checking Unit 4 emergency diesel generator fuel oil for accumulated
water after operation for greater than one hour. When identified to the licensee, the fuel
oil was checked, no water was observed, and the issue was documented in the
corrective action program as CR 2005-30252. On August 22, 2005, the licensee
identified that engineered safeguards instrument channel checks for flow transmitters
FT-4-485 and FT-4-495 had been missed for about 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> (NRC Inspection Report
50-250/2005-004 and 50-251/2005-004, Section 4OA7.2). The missed surveillance was
completed satisfactorily and documented in the corrective actions program as CR 2005-
22985. The NRC has previously identified a missed reactor coolant inventory balance,
required by licensee procedures that implement technical specification 4.4.6.2.1.c, as
documented in NRC Report 50-250/2005-003 and 50-251/2005-003, Section 1R22,
Surveillance Testing. The inspectors observed that the licensee routinely had a number
of technical specification surveillances in the grace period prior to completion.
The inspectors also identified a trend in untimely or incomplete submittals of licensee
event reports. The inspectors in this report dispositioned in LER 05000250/2005-001,
the failure of the licensee to report in the LER, the method of discovery for a procedural
error (not logging an out-of-service component in the Equipment Out-of-Service
logbook). The inspectors also dispositioned the late submittal (more than 60 days after
discovery) of Licensee Event Report 05000251/2005-003 for an incorrectly wired relay.
NRC Inspection Report 50-250 and 50-251/2005-004 dispositioned the late submittal of
an LER for a missed surveillance in Licensee Event Report 05000250/2005-003. Also,
LER 50-250/2005-004, which described the failure of an emergency containment filter
fan was submitted 76 days after the event and this late submittal was a minor violation.
4OA3 Event Followup
.1
(Closed) Licensee Event Report 05000250/2005-001: Mode Increase While in
Technical Specification Shutdown Action Statement
On January 1, 2005, Unit 3 entered Technical Specification Mode 2 (startup) while a
Technical Specification Limiting Condition for Operation (LCO) was not met.
Specifically, while a reactor startup was being conducted, control-room operators
declared the 3A ICW header inoperable, entered Technical Specification 3.7.3, and
began backwashing the 3A intake cooling water basket strainer. Before restoring the
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cooling water header, the unit entered Mode 2, where it is required to have three intake
cooling water pumps and two intake cooling water headers operable. Technical Specification 3.0.4 prohibits entry into an operational mode (reactor startup) when the
conditions for a limiting condition for operation are not met. The licensee determined
the cause of the event to be operator error, in that the control-room operator who
performed the backwash evolution did not adequately coordinate activities with
operators conducting the reactor startup. When identified by licensee personnel during
review of plant status, the issue was documented in the corrective action program and
precautions were added to the applicable procedures to prevent recurrence. The finding
was more than minor because it had a credible impact on safety when one train of
mitigating equipment was inadvertently removed from service during mode increase
operations. The issue screened as Green, using NRC Manual Chapter 0609, Appendix
AProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609, Appendix</br></br>A" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., Attachment 1, because there was no loss of mitigating function and the one train of
mitigating equipment was affected for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors reviewed the
LER and CR 2005-21, which documented this event in the licensees corrective action
program, to verify that the corrective actions had been implemented. This licensee
identified finding involved a violation of Technical Specification 3.0.4 and the
enforcement aspect is discussed in Section 4OA7.4. The failure of the licensee to
report in the LER the method of discovery for the procedural error (not logging an out-of-
service component in the Equipment Out-of-Service logbook), was considered a
violation of Minor significance. The LER is closed.
.2
(Closed) Licensee Event Report 05000251/2005-003: Incorrectly Wired P-10 Relay
Renders One of Two Inputs to P-7 Interlock Inoperable for a Single Train of At-Power
On June 3, 2005, the licensee identified that wiring in the B train of the reactor trip
system was incorrect, rendering a portion of the circuitry in one of the two redundant
trains of protection inoperable. The mis-wiring prevented certain reactor trips from
being enabled by nuclear instrument inputs, however redundant turbine first stage input
remained available and no instances of operation without full reactor protection were
identified. The cause of the mis-wiring was inadequate post-maintenance testing of
work on the circuitry in 1997. When identified by the licensee during maintenance, the
circuitry was correctly wired and tested, and post maintenance testing procedures were
revised to assure that all contacts are tested/verified when relay maintenance is
performed. The issue was entered into the corrective action program as CR 2005-
16436. Because the redundant turbine first stage pressure input to the protection
channel was always available, no instances of operation with a degraded reactor trip
capability were identified and the incorrect wiring constitutes a violation of minor
significance that is not subject to enforcement action in accordance with Section VI of
the NRC Enforcement Policy. The late submittal of the LER was a violation of minor
significance. The LER is closed.
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.3
The B Turbine Driven Auxiliary Feedwater (TDAFW) Pump Failed Inservice Test on
November 7, 2005.
a.
Inspection Scope
The B TDAFW pump exhibited high vibration (greater than inservice testing limits) on
the inboard radial bearing on November 7, 2005. The inspectors evaluated the
licensees actions related to the high vibrations as well as reviewed historical inservice
test data and oil sample analyses. The inspectors also discussed the occurrence with
plant engineers to examine the circumstances surrounding the problem.
b.
Findings
Introduction: An Apparent Violation (AV) of Technical Specification 3.7.1.2 was
identified for an inoperable auxiliary feedwater pump with a contributing violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action" for failure of the licensee to
promptly identify and correct a significant condition adverse to quality affecting the "B"
turbine driven auxiliary feedwater (TDAFW) pump. Specifically, the "B" TDAFW pump
exhibited high vibration during routine inservice tests following the replacement of the
pump inboard journal bearing in September 2003. Periodic oil samples taken since
2003 were also abnormal and on occasion, the bearing was reported to have high
temperature. Plant staff were aware of the continued high vibration but did not declare
the pump inoperable and take corrective action. Subsequently, on November 7, 2005, a
test of the "B" TDAFW pump was halted due to increasing vibration above the inservice
testing limit. The increased vibration was later determined by the licensee to be directly
related to the pump inboard journal bearing that was installed incorrectly on September
10, 2003.
Description: During testing on November 7, 2005, the B TDAFW pump inboard journal
bearing exhibited high vibration and was hot to the touch. The vibration reading was
recorded as 0.8 in/sec and the test was promptly halted. The next day, a licensee
inspection identified uneven tooth wear on the pump coupling and evidence of grease
caking. Further inspection of the inboard journal bearing found that the bearing was
installed incorrectly. This incorrect installation which occurred during the September
10, 2003 pump replacement, caused inadequate lubrication to the bearing and caused
flaking of the babbit.
Based on review of the B TDAFW pump historical vibration data, the inspectors found
that inboard vertical vibration was .30 in/sec in September 2003, which was higher than
.15 in/sec prior to pump bearing replacement. Subsequently the inboard vertical
vibration trended high until September 13, 2004, when the pump inboard vertical
vibration reading was at .38 in./sec and in the Alert range (>.32 in/sec and <.70 in/sec).
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More frequent tests were performed (11/18/2004 - .375 in/sec, 12/6/2004 - .441 in/sec,
1/10/2005 - .404 in/sec, 1/31/2005 - .405), and vibration remained in the Alert range until
February 24, 2005, when the licensee initiated actions which included pump coupling
alignment, tightening of the pump base bolting, and filtration of turbine/pump oil
reservoir. However, this maintenance was not effective in that the inboard vertical
vibration reading remained high at .305 in/sec. Subsequent tests were performed
(3/22/2005 - .48 in/sec, 3/28/2005 - .44 in/sec; 5/23/2005 - .45 in/sec, 8/15/2005 - .47
in/sec, 09/12/2005 - .52 in/sec) and the pump inboard vertical vibration readings
remained high until November 7, 2005, when the pump exceeded the inservice test
operability limit of 0.7 in/sec with a reading of 0.8 in/sec. The inspectors noted that
during surveillance runs, the turbine is operated for a nominal 30 minutes. The
inspectors reviewed testing data and determined that the oil samples for past periods
showed degradation (for example Abnormal on Dec 6, 2004), and bearing temperatures
were recorded as elevated during post trip operation on March 22, 2005.
Analysis: The inspectors determined that installing the B AFW pump which was
inoperable due to the radial bearing not being properly aligned, was a performance
deficiency which existed for greater than the allowed TS outage time. Further, the
licensee not having discovered the improper installation, which was evident in degrading
vibration, abnormal oil samples, and a hot-to-touch bearing during pump operation, was
a contributing corrective actions effectiveness issue. The vibration increased to a
sufficient magnitude to cause operators to halt pump operation on November 7, 2005
and perform an investigation that revealed improper installation of the pump radial
bearing. The finding was determined to be more than minor because failure of the
licensee to promptly identify and correct conditions adverse to quality resulted in an
unreliable train of auxiliary feedwater, which is a mitigating system shared by both units.
NRC Phase 1 and Phase 2 Significance Determination Process analyses determined
that this finding is greater than Green because the "B" TDAFW pump was not capable
of performing its function for its mission time (24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) from September 10, 2003 when
the bearing was incorrectly installed, until November 8, 2005, when it was corrected.
Additionally for the NRC evaluation, the pump failure was assumed to be
non-recoverable since repairs would have required significant equipment disassembly.
An SDP Phase 3 analysis was performed and concluded the issue to be of low to
moderate safety significance, Preliminary White. This potential finding is also related to
the cross-cutting area of problem identification and resolution due to the failure to
promptly resolve a known condition adverse to quality.
Enforcement: Technical Specification 3.7.1.2 requires two independent auxiliary
feedwater trains including 3 pumps during plant operation. Action statement 3 states, in
part, that with a single auxiliary feedwater pump inoperable, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, verify
operability of two independent auxiliary feedwater trains and restore the inoperable
pump to operable status within 30 days, or place the affected units in at least Hot
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Standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. 10 CFR 50, Appendix B, Criterion XVI, Corrective
Action, states, in part, that measures shall be established to assure that conditions
adverse to quality, are promptly identified and corrected.
Contrary to the above, the licensee failed to restore the inoperable B auxiliary
feedwater pump within 30 days, and did not place the unit in at least Hot Standby during
this time. In this case, the B auxiliary feedwater pump was placed in service on
September 10, 2003, in an inoperable condition due to a misaligned radial bearing, and
the inoperable condition was not identified until November 7, 2005. In addition, the
licensee failed to identify and correct the condition during this time, even though pump
bearing vibration levels and oil samples provided indication of the significant adverse
condition. This apparent violation is identified as AV 05000250, 251/2005005-02, AFW
Pump B out of Service Greater than TS Allowed Due to Incorrect Bearing Installation.
The licensee entered this issue in the Corrective Action Program as condition report
(CR) 2005-30750.
4OA5 Other Activities
(Closed) Unresolved Item (URI) 05000250,251/2002006-01: Adequacy of SBO
Strategy/Analysis and Loss of AC Power EOPs
During the Safety System Design and Performance Capability Inspection (SSDPC),
NRC Inspection Report (IR) 05000250, 251/02-06, the inspectors observed that the
licensees coping strategy for station blackout (SBO) changed in 1998 from the original
SBO coping strategy, approved in 1990, of maintaining the plant in hot standby for 8
hours and supplying reactor coolant pump (RCP) seal cooling, to a strategy of reactor
coolant system cooldown without RCP seal cooling. This item was reviewed in a follow-
up inspection documented in NRC IR 05000250, 251/03-07. During the SSDPC and
follow-up inspection, the inspectors were unable to verify that changes made to the
emergency operating procedures, based on the revised coping strategy, did not
adversely impact the licensees ability to mitigate an SBO. This unresolved item
remained open pending NRC technical review of a revised station blackout (SBO)
thermo-hydraulic analysis performed by the licensee.
The NRCs technical review of the licensees evaluation concluded that the licensees
thermo-analysis was acceptable. This item is closed.
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
22
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
Enclosure
4OA6 Exit
Exit Meeting Summary
The resident inspectors presented the inspection results to Mr. Webster and other
members of licensee management at the conclusion of the inspection on January 12,
2005. Additionally, the licensee was informed of the Preliminary White Apparent
Violation on January 27, 2005. The inspectors asked the licensee whether any of the
material examined during the inspection should be considered proprietary. The licensee
did not identify any proprietary information.
4OA7 Licensee Identified Violations
The following violations of very low safety significance (Green) were identified by the
licensee and are violations of NRC requirements which meet the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600 for being dispositioned as NCVs:
.1
Technical Specification 3.4.9.2.c requires that pressurizer - spray water differential
temperature shall be limited to a maximum of 320 degrees or restore the temperature to
within the limits within 30 minutes. Contrary to the above, on November 1, 2005, during
plant cooldown, the pressurizer - spray water differential temperature was 360 degrees
and not restored to within limits for six hours. The issue was identified by the licensee
during a post-cooldown review of plant parameters. When identified, the licensee
entered the occurrence in their corrective actions program and completed an
engineering evaluation. The issue was more than minor, having affected the barrier
integrity cornerstone that assures the integrity of the reactor coolant system. The issue
screened as Green using NRC Manual Chapter 0609, Appendix A, Attachment 1 after
the structural integrity of the pressurizer was evaluated and the transient was found to
have been within engineering design limits. The issue is in the licensee corrective
action program as CR 2005-29846.
.2
Technical Specification 6.8.1.a, requires that the written procedures of NRC Regulatory
Guide 1.33, Revision 2, Appendix A, February 1978, be implemented. The regulatory
guide, Attachment A, Section 1, includes procedures for Equipment Control (Tagging).
FPL implements this requirement, in part, with procedure 0-ADM-212, In-Plant
Equipment Clearance Orders, which states in Step 4.18.1, Danger Tag, that the
position of the component may not be altered in any way. Contrary to the above, on
November 17, 2005, FPL failed to implement 0-ADM-212, when the position of danger
tagged component C343C (B boric acid storage tank sample valve) was altered when a
technician operated a valve that was danger tagged shut with tag 0-05-002-00001.
When identified, the issue was documented in the corrective action program and a
human performance review was initiated. There were no immediate safety
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
23
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
Enclosure
consequences. The performance deficiency was more than minor because operation of
a danger tagged valve on a system covered in technical specifications (TS 3.1.2.1) was
considered a precursor to a significant event, that being mis-operation of a danger
tagged valve that affects nuclear safety. The issue screened as Green using NRC
Manual Chapter 0609, Appendix A, Attachment 1, because in this case, operation of the
valve did not result in any safety system inoperabilities or plant transients. The issue is
in the licensee corrective action program as CR 2005-31725.
.3
Technical Specification 3.4.1.3 requires that in operational Mode 4, with no reactor
coolant pumps in operation, residual heat removal loops A and B shall be operable and
at least one of the loops shall be in operation. Further, both residual heat removal
pumps may be deenergized for up to one hour provided there are no boron dilution
activities and saturation margin is maintained. Contrary to the above, on November 1,
2005, with Turkey Point Unit 4 in Mode 4 and no reactor coolant pumps in operation,
both residual heat removal pumps were stopped for more than one hour (two hours and
five minutes). The issue was more than minor, affecting the Initiating Events
Cornerstone, because with no forced circulation in the reactor, thermal stratification of
the reactor coolant system could occur that may cause reactivity changes outside the
capability of operator recognition and control, should a boron dilution occur. The issue
screened as Green, using NRC Manual Chapter 0609, Appendix A, Attachment 1, as a
transient initiator contributor, because no boron dilution occurred and all mitigating
systems remained available. When identified, the licensee documented the problem in
the corrective action program as CR 2005-29796.
.4
Technical Specification 3.0.4 requires, in part, that entry into an operational mode shall
not be made when the conditions for the Limiting Condition for Operations are not met.
Contrary to the above, on January 1, 2005, Turkey Point Unit 3 entered operational
Mode 2 (Startup) from Mode 3 (Hot Standby) while the conditions for Limiting Condition
for Operation 3.7.3, were not met when one train of intake cooling water was inoperable
due to basket strainer backwash. The violation existed for 52 minutes. The finding was
more than minor because it had a credible impact on safety when one train of mitigating
equipment was inadvertently removed from service during mode increase operations.
The issue screened as Green, using NRC Manual Chapter 0609, Appendix A,
Attachment 1, because there was no loss of mitigating function and the one train of
mitigating equipment was affected for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. When identified by licensee
personnel during review of plant status, the issue was documented in the corrective
action program and precautions were added to the applicable procedures to prevent
recurrence. The issue is in the licensee corrective action program as CR 2005-21.
ATTACHMENT: SUPPLEMENTAL INFORMATION
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel:
S. Greenlee, Engineering Manager
T. Jones, Site Vice-President
M. Moore, Corrective Actions Supervisor
M. Murray, Emergency Preparedness Supervisor
M. Navin, Operations Manager
K. OHare, Radiation Protection and Safety Manager
W. Parker, Licensing Manager
M. Pearce, Plant General Manager
D. Poirier, Maintenance Manager
W. Prevatt, Work Controls Manager
W. Webster, Senior Vice President, Operations
NRC personnel:
B. Desai, Acting Projects Branch Chief, Region II
J. Polickoski, Reactor Engineer, Region II
W. Travers, Region II Administrator
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
05000250/ 2005005-
02 and
05000251/2005005-
02
AFW Pump B out of Service Greater than TS Allowed Due
to Incorrect Bearing Installation (4OA3.3)
Opened and Closed
05000250/2005005-
01 and
05000251/2005005-
01
Failure to Correct Repeated Problems with Auxiliary
Feedwater Pump Manual Speed Control (4OA2.2)
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
A-1
ATTACHMENTS 2 AND 3 CONTAIN PROPRIETARY INFORMATION
Attachment
Attachment
Closed
Mode Increase While in Technical Specification Shutdown
Action Statement (4OA3.1)
05000250,251/20020
06-01
LER
Incorrectly Wired P-10 Relay Renders One of Two Inputs to
P-7 Interlock Inoperable for a Single Train of At-Power
Reactor Trips (4OA3.2)
Strategy/Analysis and Loss of AC Power EOPs Adequacy
of SBO (4OA5)
LIST OF DOCUMENTS REVIEWED
Section 4OA5, Other
Response to Task Interface Agreement - TIA 2003-03, Regarding Turkey Point Nuclear Plant,
Units 3 and 4, Station Blackout Coping Analysis, (TAC Nos. MB8728 and MB 8729), dated
9/12/05
NRC Report No. 50-250,251/02-06
NRC Report No. 50-250,251/03-07
UFSAR dated 9/29/05