ML061070659
ML061070659 | |
Person / Time | |
---|---|
Site: | Millstone ![]() |
Issue date: | 04/17/2006 |
From: | Paul Krohn NRC/RGN-I/DRP/PB6 |
To: | Christian D Dominion Resources |
References | |
IR-06-006 | |
Download: ML061070659 (33) | |
See also: IR 05000336/2006006
Text
April 17, 2006
Mr. David A. Christian
Sr. Vice President and Chief Nuclear Officer
Dominion Resources
5000 Dominion Boulevard
Glenn Allen, VA 23060-6711
SUBJECT: MILLSTONE POWER STATION - NRC PROBLEM IDENTIFICATION AND
RESOLUTION INSPECTION REPORT 05000336/2006006 AND
Dear Mr. Christian:
On March 3, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed a team
inspection at the Millstone Power Station, the enclosed report documents the inspection
findings, which were discussed on March 3, 2006, with Mr. J. Alan Price and other members of
your staff.
This inspection was an examination of activities conducted under your license as they relate to
the identification and resolution of problems, and compliance with the Commissions rules and
regulations and the conditions of your operating license. Within these areas, the inspection
involved examination of selected procedures and representative records, observation of
activities, and interviews with personnel.
On the basis of the sample selected for review, the inspectors concluded that in general,
problems were properly identified, evaluated, and corrected. There were five Green findings
identified during the inspection: three associated with ineffective problem identification, one
associated with prioritization and evaluation of issues, and one associated with ineffective
corrective actions. The three findings associated with ineffective problem identification included
the failure to perform evaluations for boric acid leaks, failure to include acceptance criteria in
turbine-driven auxiliary feedwater pump maintenance procedures, and the inadequate
evaluation of the suitability of a charging pump discharge dampener modification. The finding
associated with prioritization and evaluation of issues included failure to evaluate and correct
turbine-driven auxiliary feedwater pump governor control valve stem binding problems that
resulted in overspeed trips. The finding associated with ineffective corrective actions included
the failure to implement effective corrective actions associated with repetitive leak rate testing
failures of a containment isolation valve.
These findings were determined to be violations of NRC requirements. However, because of
their very low safety significance and because they were entered into your corrective action
program, the NRC is treating these findings as non-cited violations, in accordance with Section
VI.A.1 of the NRCs Enforcement Policy. If you deny these non-cited violations, you should
provide a response with the basis for your denial within 30 days of the date of this inspection
report, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region I; the
Mr. David A. Christian 2
Director, Office of Enforcement, U. S. Nuclear Regulator Commission,
Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Millstone Facility.
In addition, examples of minor problems were identified including the failure to retain quality
assurance records and performing post-maintenance testing on a safety-related component
using a minor work control procedure.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response (if any) will be available electronically for public inspection in the
NRC Public Document Room or from the Publicly Available Records (PARS) component of
NRCs document system (ADAMS). ADAMS is accessible from the NRC Website at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Paul G. Krohn, Chief
Projects Branch 6
Division of Reactor Projects
Docket Nos.: 50-336, 50-423
Enclosure: Inspection Report 05000336/2006006 and 05000423/2006006
w/Attachment: Supplemental Information
cc w/encl:
J. A. Price, Site Vice President, Millstone Station
C. L. Funderburk, Director, Nuclear Licensing and Operations Support
D. W. Dodson, Supervisor, Station Licensing
L. M. Cuoco, Senior Counsel
C. Brinkman, Manager, Washington Nuclear Operations
J. Roy, Director of Operations, Massachusetts Municipal Wholesale Electric Company
First Selectmen, Town of Waterford
R. Rubinstein, Waterford Library
B. Sheehan, Co-Chair, NEAC
E. Woollacott, Co-Chair, NEAC
E. Wilds, Director, State of Connecticut SLO Designee
J. Buckingham, Department of Public Utility Control
G. Proios, Suffolk County Planning Dept.
R. Shadis, New England Coalition Staff
G. Winslow, Citizens Regulatory Commission (CRC)
S. Comley, We The People
D. Katz, Citizens Awareness Network (CAN)
R. Bassilakis, CAN
Mr. David A. Christian 3
J. M. Block, Attorney, CAN
P. Eddy, Electric Division, Department of Public Service, State of New York
P. Smith, President, New York State Energy Research and Development Authority
J. Spath, SLO Designee, New York State Energy Research and Development Authority
Mr. David A. Christian 4
Distribution w/encl (VIA E-MAIL):
S. Collins, RA
M. Dapas, DRA
B. Sosa, RI OEDO
D. Roberts, NRR
V. Nerses, NRR
E. Miller, NRR
M. Giles, Senior Resident Inspector (Calvert Cliffs Nuclear Power Station)
S. Schneider, Senior Resident Inspector
S. Kennedy, Resident Inspector
J. Benjamin, Resident Inspector
E. Bartels, Resident OA
P. Krohn, RI
B. Norris, RI
S. Barber, RI
Region I Docket Room (with concurrences)
ROPreports@nrc.gov
SISP Review Complete:__PGK___ (Reviewers Initials)
DOCUMENT NAME: E:\Filenet\ML061070659.wpd
After declaring this document An Official Agency Record it will be released to the Public.
To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure
"E" = Copy with attachment/enclosure "N" = No copy
OFFICE RI/DRP RI/DRP
NAME MGiles PKrohn
DATE 04/ /06 04/ /06
OFFICIAL RECORD COPY
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No.: 50-336, 50-423
Report No.: 05000336/2006006 and 05000423/2006006
Licensee: Dominion Nuclear Connecticut, Inc.
Facility: Millstone Power Station, Units 2 and 3
Location: Waterford, CT 06385
Dates: February 13 - 17, 2006 and
February 27 - March 3, 2006
Inspectors Leader: Mark A. Giles, Senior Resident Inspector, DRP
Inspectors: Silas Kennedy, Resident Inspector, DRP
Todd Fish, Operations Engineer, DRS
Peter Presby, Operations Engineer, DRS
Jennifer Bobiak, Reactor Inspector, DRS
Sammy McCarver, Reactor Inspector, DRS
Approved by: Paul G. Krohn, Chief
Reactor Projects Branch 6
Division of Reactor Projects
i Enclosure
SUMMARY OF FINDINGS
IR 05000336/2006-006, IR 05000423/2006-006; 2/13/06 - 3/3/06; Millstone Nuclear Plant,
Units 2 and 3; biennial baseline inspection of the identification and resolution of problems.
Violations were identified in the areas of effectiveness of problem identification, prioritization
and evaluation of issues, and effectiveness of corrective actions.
This inspection was conducted by regional and resident inspectors. Five Green findings of very
low safety significance were identified during this inspection and were classified as non-cited
violations. These findings were evaluated using the significance determination process (SDP).
Identification and Resolution of Problems
The inspectors identified that the licensee was effective at identifying problems and entering
them into the corrective action program (CAP). The licensees effectiveness at problem
identification was evidenced by the relatively few deficiencies were identified by external
organizations (including the NRC) that had not been previously identified by the licensee, during
the review period. The licensee effectively used risk in prioritizing the extent to which individual
problems would be evaluated and in establishing schedules for implementing corrective actions.
Corrective actions, when specified, were generally implemented in a timely manner. Licensee
audits and self-assessments were found to be generally effective. On the basis of interviews
conducted during this inspection, workers at the site felt free to input safety concerns and
issues into the CAP program.
The inspectors, however, identified that the licensee failed to identify certain issues including
errors in implementing the established boric acid corrosion control program (in light of a
Problem Identification and Resolution (PI&R) site assessment that was performed in
November 2005 that considered this area); the failure to include industry guidance associated
with a turbine-driven auxiliary feedwater pump control valve critical measurement in a
maintenance procedure, and inadequate design scoping associated with a modification that
installed discharge dampeners in the Unit 2 charging system. The inspectors also concluded
that following identification and documentation of excessive Unit 3 TDAFW pump internal
stuffing box wear in April 2005, the licensee failed to evaluate and understand the condition so
as to prevent a recurring overspeed trip failure that occurred on January 9, 2006. In addition, it
was determined that corrective actions associated with local leak rate testing were incomplete
in that the actions did not prevent the repetitive failure of a containment isolation valve.
The use of the CAP by the security organization was also inspected and the results of this
inspection are contained in NRC Inspection Report 05000336/2006007, 05000423/2006007.
A. NRC Identified and Self-Revealing Findings
Cornerstone: Initiating Events
- Green. The inspectors identified a Green non-cited violation (NCV) of
10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings
for Dominions failure to follow Boric Acid Corrosion Control Program (BACCP)
procedures. Specifically, plant personal routinely failed to perform boric acid
ii Enclosure
leak evaluations as required per Dominion procedure DNAP-1004, Boric Acid
Corrosion Control Program, despite the specified threshold having been met.
This finding is more than minor because it is associated with the Initiating Events
Cornerstone attribute of human performance and it affects the cornerstones
objective of limiting the likelihood of those events that upset plant stability and
challenge critical safety functions during shutdown as well as power operations.
The licensee entered this condition into the corrective action program as
CR-06-02088. This finding was characterized as a loss-of-coolant-accident
(LOCA) initiator and was determined to be of very low safety significance
(Green) because it did not result in exceeding the Technical Specification limit
for identified rector coolant system (RCS) leakage or affect other mitigation
systems resulting in a total loss of their safety function. Corrective actions
included a planned revision to the Boric Acid Corrosion Control program to
ensure evaluations are performed and documented. In addition, the licensee
conducted a Boric Acid Corrosion Control program peer review using another
nuclear power station boric acid program owner. This finding is related to the
cross-cutting area of human performance in that on at least 22 occasions,
station personnel did not follow established station procedures requiring boric
acid evaluation. (Section 4OA2.1.c.1)
Cornerstone: Mitigating Systems
- Green. The inspectors identified a Green NCV of 10 CFR 50, Appendix B,
Criterion XVI, Corrective Actions, for the failure to take effective corrective
action to prevent a repeat failure of the Unit 3 turbine-driven auxiliary feedwater
(TDAFW) pump. Specifically, following identification and documentation of
excessive internal stuffing box wear, which was identified following an overspeed
trip event that occurred in April 2005, the licensee failed to fully evaluate this
condition which was later documented as a contributing cause to a recurring
failure that occurred on January 9, 2006. The licensee entered this condition
into their corrective action program as CR-06-00244. Corrective actions for this
issue included repacking of the TDAFW pump governor control valve, repair of a
cam plate, and plans to conduct a stuffing box repair within three months of the
January 2006 pump failure.
This finding is more than minor because it is associated with the Mitigating
Systems Cornerstone and affects the cornerstone objective of ensuring the
availability, reliability, and capability of systems that respond to initiating events
to prevent undesirable consequences. Specifically, because the degraded
stuffing box was not adequately evaluated and corrected in April 2005, the
reliability of the TDAFW pump was adversely affected. Following Phase 1, 2,
and 3 SDP evaluations, this finding was determined to be of very low safety
significance (Green) since TDAFW pump recovery credit was given during a
restart attempt that would occur during a design basis event. This finding is
related to the cross-cutting area of problem identification and resolution in that
the licensee did not fully evaluate and correct an identified degraded condition.
(Section 4OA2.2.c.1)
iii Enclosure
- Green. The inspectors identified a Green NCV of 10 CFR 50, Criterion V,
Instructions, Procedures, and Drawings for failing to include appropriate
acceptance criteria associated with the measurement of the Unit 3 TDAFW
pump governor control valve stuffing box inner diameter in the applicable
maintenance procedure. In addition, the maintenance procedure did not specify
the equipment required to measure the control valve stem/gap measurements
and did not require the recording of measurements needed to verify the
maintenance activity had been satisfactorily accomplished in accordance with
vendor requirements. The licensee evaluated this issue for immediate
operability and entered the issue into their corrective action program as
CR-06-02043 and CR-06-02044. Corrective actions included revising the
maintenance procedure to update the clearance values as well as instructing
maintenance system team personnel on the event relative to utilizing the correct
MT&E for the work scope.
This finding is more than minor because it affected the procedure quality
attribute of the Mitigating Systems Cornerstone. Specifically, if left uncorrected,
the finding would become a more significant safety concern as governor stuffing
box internal diameters continued to increase resulting in additional control valve
stem binding issues and associated TDAFW pump overspeed and failure events.
The inspectors determined that the finding was of very low safety significance
(Green) because the finding did not involve a design or qualification deficiency,
represent an actual loss of system or TDAFW pump safety function, or involve
seismic, flooding, or severe weather initiating events. This finding is related to
the cross-cutting aspect of problem identification and resolution in that the
licensee failed to translate appropriate vendor acceptance criteria into the
TDAFW governor control valve maintenance procedure despite receipt of new
vendor requirements which were published and available in 1999.
(Section 4OA2.1.c.2)
- Green. The inspectors identified a Green NCV of 10 CFR 50, Appendix B,
Criterion III, Design Control associated with the Unit 2 charging system pump
discharge dampener modification. Specifically, the licensees review of the
design modification failed to adequately consider the suitability of the dampener
in that a potential common mode failure mechanism associated with gas binding
of the charging pump suction was not considered nor evaluated. This condition
was entered into the licensees corrective action program as CR-06-02382.
Corrective actions include performing a root cause to, in part, determine why the
design process and other organizational factors that installed the bladders did
not identify the potential common mode failure.
The finding was more than minor because it affected the availability, reliability,
and capability objective of the Mitigating System Cornerstone and its associated
design control attribute. Specifically, inadequate design control caused
Dominion to not fully consider the affects of a discharge dampener bladder
failure on the common suction of the Unit 2 charging pumps, a condition which,
on January 9, 2006, led to the momentary loss of the charging system. Based
upon the IMC 0609, Appendix A, Significance Determination of Reactor
Inspection Findings for At-Power Situations, Phase 1 screening worksheets, this
iv Enclosure
finding required a Phase 2 evaluation since the finding represented a loss of
system safety function. Based upon the Phase 2 results, the Region I Senior
Reactor Analyst (SRA) conducted a Phase 3 evaluation. The cumulative
increase in core damage probability for this condition was determined to be in
the low E-8 range and of very low safety significance (Green). This finding has a
problem identification and resolution cross-cutting aspect in that evaluations and
corrective actions performed by the licensee were inadequate to prevent
charging system anomalies despite the identification of a small boric acid leak
from the cap of the B charging pump discharge pulsation dampener, an
indication of a failed pulsation dampener for which no corrective maintenance
was performed. (Section 4OA2.1.c.3)
Cornerstone: Barrier Integrity
- Green. The inspectors identified a Green NCV of 10 CFR 50, Appendix B,
Criterion XVI, Corrective Action, for failure to take adequate corrective actions
to prevent repetitive local leak rate test failures associated with the Unit 3 reactor
plant chilled water system (CDS) inboard containment isolation valve,
3CDS*CTV40A. As a result, there was a loss of redundancy which reduced
reliability of the containment isolation function. This condition was entered into
the licensees corrective action program as CR-05-10651, a condition report
which documented a licensee action to create a plan to resolve the failures.
This finding is more than minor because it is associated with the Barrier Integrity
Cornerstone objective of maintaining containment functionality and the attribute
of structure/system/component (SSC) and Barrier Performance. The finding is
of very low safety significance because there was no actual open pathway in the
physical integrity of the reactor containment or an actual reduction of the
atmospheric pressure control function of the containment. This finding is related
to the cross-cutting area of problem identification and resolution in that the
licensee did not implement effective corrective actions to prevent a recurring
component failure. (Section 4OA2.3.c.1)
B. Licensee-Identified Violations
None.
v Enclosure
Report Details
4. OTHER ACTIVITIES (OA)
4OA2 Problem Identification and Resolution (Biennial - 71152B)
.1 Effectiveness of Problem Identification
a. Inspection Scope
The inspectors reviewed the procedures, listed in the Attachment to this report,
describing the corrective action program (CAP) at Dominions Millstone Units 2 and 3
Nuclear Power Plants. The licensee identifies problems by initiating condition reports
(CRs) for conditions adverse to quality, human performance problems, equipment
non-conformances, industrial or radiological safety concerns, and other significant
issues. The CRs are subsequently screened for operability, categorized by priority and
significance (Level 1, 2 and N), and assigned appropriately for evaluation and resolution.
The inspectors considered risk insights from the NRCs and Millstones risk analyses to
focus the sample selection and plant tours on risk-significant systems and components.
The inspectors reviewed CRs selected across the seven cornerstones of safety in the
NRCs Reactor Oversight Process (ROP) to determine if problems were being properly
identified, characterized, and entered into the CAP for evaluation and resolution. The
inspectors selected items from the maintenance, operations, engineering, emergency
planning, security, radiological protection, and oversight programs to ensure that the
licensee was appropriately considering problems identified in each functional area. The
inspectors used this information to select a risk-informed sample of CRs that had been
issued since the last NRC PI&R inspection, which was completed in November 2004. In
accordance with NRC inspection procedure 71152, the Unit 2 charging system was
selected for an expanded review covering the last five years.
In addition to CRs, the inspectors conducted plant tours and selected items from other
processes at Millstone to verify that problems identified in these areas were entered into
the corrective action program when appropriate. Specifically, the inspectors reviewed a
sample of work requests, engineering documents, operator log entries, control room
deficiency logs, operator work-arounds, operability determinations, system health
reports, and temporary modifications. The documents were reviewed to ensure that
underlying problems associated with each issue were appropriately considered for
resolution via the corrective action process. In addition, the inspectors interviewed plant
staff and management to determine their understanding of and involvement with the
CAP. The CRs and other documents reviewed, and a list of key personnel contacted,
are listed in the Attachment to this report.
The inspectors reviewed a sample of the licensees audits and self-assessments,
including the most recent assessment of the CAP, conducted in November 2005,
quarterly assessment reports, and departmental self-assessments. This review was
performed to determine if problems identified through these assessments were entered
into the CAP, and whether the identified issues were dispositioned appropriately
Enclosure
2
commensurate with the safety significance of the issue. The effectiveness of the audits
and self-assessments were evaluated by comparing audit and self-assessment results
against self-revealing and NRC-identified findings, and current observations during the
inspection.
b. Assessments
The inspectors concluded that the licensee was generally effective at identifying
problems and entering them into the corrective action program. The CRs that are
written were classified by their significance as Level I, 2, or N. Condition reports
classified as a Level I require a root cause evaluation (RCE) and Level 2 CRs require an
apparent cause evaluation (ACE). Level N CRs do not typically require a detailed
review. The inspectors determined that station personnel demonstrated appropriate
knowledge of the corrective action program, and entered identified problems into the
program at an appropriate threshold. There were approximately 14,250 CRs generated
in 2005. The inspectors did not identify any significant conditions adverse to quality in
the maintenance, engineering, or operations tracking systems which did not have a CR
associated with them.
Relatively few deficiencies were identified by external organizations, including the NRC,
that had not been previously identified by the licensee. Also, during this inspection,
there were no instances identified where conditions adverse to quality were being
handled outside the corrective action program. Audits and self-assessments were
generally thorough; however, the inspectors did identify three missed opportunities to
identify issues and enter them into the corrective action program. The first involved the
boric acid corrosion control program (BAACP). In review of the fleet procedure that
implemented the BAACP, the inspectors noted that evaluations were not being
performed as required. In addition other BAACP requirements including having a
systematic methodology for trending and tracking boric acid leakers, and the
dispositioning of each identified leak as either emergent, monitoring, or no actions
required, were not being performed. The licensee performed a PI&R site assessment
during November 2005 and had the opportunity to identify these programmatic
deficiencies. Secondly, the licensee failed to utilize industry guidance that was made
available in 1999. Although this information was referenced in work documents used to
perform repairs of a degraded auxiliary feedwater pump governor control valve in April
2005, the licensee failed to translate this guidance into the maintenance procedure at
that time although the opportunity existed. Finally, during the implementation of a
design modification that installed discharge dampeners in the Unit 2 charging system,
although engineering personnel considered the potential for a common-mode failure
mechanism associated with gas binding, it was not adequately evaluated for suitability in
the specific application.
c. Findings
.1 Introduction. The inspectors identified a Green NCV of 10 CFR 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, for the failure to follow Boric Acid
Corrosion Control Program procedures. Specifically, plant personal routinely failed to
Enclosure
3
perform boric acid leak evaluations as required in Dominion procedure DNAP-1004,
Boric Acid Corrosion Control Program, even though the evaluation threshold criteria
contained in that procedure was met.
Description. Licensee procedure DNAP-1004, Boric Acid Corrosion Control Program,
requires that all identified boric acid leaks must be initially reported in the site corrective
action system and DNAP 1004, Attachment 1, Boric Acid Corrosion Control Program
Screening, provides severity threshold criteria for performing engineering evaluations
on the identified leaks. During the Unit 3 refueling outage (3R10) in October 2005,
identified leaks were screened using this Attachment. In several instances, however,
the threshold criteria in Attachment 1 was met but plant personnel failed to perform the
required evaluations. Instead, plant personnel routinely made value judgements on
whether or not an evaluation was needed, despite the criteria for an evaluation as stated
in DNAP-1004. For instance, systematic trending and tracking of boric acid leakers and
the dispositioning of each identified leak as either emergent, monitoring, or no actions
required was not performed. In a sample of refueling outage 3R10 screenings reviewed
by the inspectors, 23 leaks met the DNAP-1004 criteria for an evaluation, however, only
one was performed. The licensee entered this deficiency into their corrective action
program as CR 06-02088. Corrective actions included a planned revision to the Boric
Acid Corrosion Control Program to ensure that evaluations are performed and
documented. In addition, a peer review from another power station BACCP owner was
performed.
Analysis. The performance deficiency was that licensee activities affecting quality were
not accomplished in accordance with DNAP-1004, in that the licensee routinely failed to
perform boric acid leak evaluations required in that procedure. This finding is more than
minor because it is associated with the Initiating Events cornerstone attribute of human
performance and it affects 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 power operations. This finding is similar to Inspection
Manual Chapter (IMC) 0612, Appendix E, non-minor example 4a in that the licensee
routinely failed to perform engineering evaluations on similar issues, i.e. boric acid
leaks.
This finding was determined to be of very low safety significance (Green) based on
IMC 0609 Appendix A, Determining the Significance of Reactor Inspection Findings for
At-Power Situations. This finding was characterized as a LOCA initiator and was
determined to be of very low safety significance (Green) based on IMC 0609
Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power
Situations because it did not result in exceeding the Technical Specification limit for
identified rector coolant system (RCS) leakage or affect other mitigation systems
resulting in a total loss of their safety function. In addition, this performance deficiency
is related to the cross-cutting area of human performance in that station personnel failed
to follow the established station BACCP procedure. Although the threshold criteria for
performing engineering evaluations was stated in DNAP-1004, screens that met that
criteria were not appropriately dispositioned nor the required evaluation performed.
Enclosure
4
Enforcement. Code of Federal Regulations 10 CFR 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings requires, in part, that activities affecting quality
shall be prescribed by documented instructions, procedures, and drawings, of a type
appropriate to the circumstances and shall be accomplished in accordance with these
instructions, procedures, or drawings. Dominion procedure DNAP-1004, Attachment 1,
Boric Acid Corrosion Control Program Screening, provided threshold criteria for
performing engineering evaluations on boric acid leaks. Contrary to the above, in at
least 22 instances during October 2005, the licensee failed to accomplish boric acid leak
evaluations in accordance with DNAP-1004. This issue was determined to be of very
low safety significance (Green) and has been addressed in the licensees corrective
action program (CR-06-02088). Corrective actions included a planned revision to the
Boric Acid Corrosion Control Program to ensure that evaluations are performed and
documented and a peer review of the BACCP program from the another power station
BACCP owner. This violation is being treated as a non-cited violation consistent with
Section VI.A of the NRC Enforcement Policy. (NCV 05000336/423/2006006-01, Failure
to Perform Evaluations on Boric Acid Leaks)
.2 Introduction. The inspectors identified a Green NCV of 10 CFR 50, Criterion V,
Instructions, Procedures, and Drawings for failing to include appropriate acceptance
criteria associated with the measurement of the TDAFW pump governor control valve
stuffing box inner diameter in a Unit 3 TDAFW pump maintenance procedure.
Description. On January 9, 2006, the TDAFW pump tripped on overspeed during a
routine quarterly surveillance. During subsequent troubleshooting, maintenance
personnel performed a valve stem motion test and observed stem binding. Following
additional troubleshooting, mechanics disassembled the governor control valve and
replaced the governor. Subsequent vendor testing showed no problems or concerns
with the governor performance. The licensee re-assembled the control valve with a new
stem and packing. The licensee conducted a final operability run successfully on
January 12, 2006.
The inspectors reviewed MP 3762AB, Terry Turbine Control Valve Maintenance; work
order M3-06-00466, 3FWA*P2 Control Valve Rebuild and Governor Replacement; and
references associated with the TDAFW pump governor control valve maintenance
accomplished on January 10, 2006. The inspectors noted that in April 1999, Dominion
made a technical manual change to incorporate vendor guidance for the TDAFW pump
governor control valve under design change notice (DCN) DM3-01-0046-99. This DCN
provided vendor requirements in response to an industry issue associated with terry
turbine governor control valve stem binding. The inspectors identified that the vendors
acceptance criteria for stuffing box inner diameter (ID) was not listed in the maintenance
procedure. As a result, this critical dimension was not taken into account prior to the
re-assembly of the control valve on January 10, 2006.
In addition, the inspectors noted that the Maintenance and Test Equipment (M&TE)
required to perform critical measurements was not listed in the maintenance procedure.
Specifically, the micrometer required to measure stem/spacer gap measurements was
Enclosure
5
not listed in the procedure as M&TE required to accomplish this task. As a result, the
micrometer used to take stem/spacer gap measurements on January 10, 2006, during
the governor control valve re-assembly was not accurate enough to ensure that the
measurements met the acceptance criteria. The vendor required a minimum cold gap
measurement of 0.0015 inches to prevent stem binding due to thermal expansion as
identified in NRC Information Notice 98-24, Stem Binding in Turbine Governor Valves in
Reactor Core Isolation Cooling and Auxiliary Feedwater Systems. The tolerance of the
micrometer used was +0.001/-0.0005 inches. The inspectors also identified that the
maintenance procedure did not include steps to record some critical dimensions such as
stuffing box ID, stem/spacer gap measurements, and stem diameter; thus, these
dimensions for the installed valve were not verifiable to ensure the maintenance activity
was satisfactorily accomplished in according with the vendors requirements. The
licensee evaluated this issue for immediate operability and entered this issue into their
corrective action program under CR-06-02043 and CR-06-02044.
Analysis. The performance deficiency was the failure to translate stuffing box ID
acceptance criteria from the vendors technical manual to procedure MP 3762AB, Terry
Turbine Control Valve Maintenance. In addition, the maintenance procedure did not
specify the M&TE required to measure critical dimensions and did not require the
recording of measurements needed to verify the maintenance activity was satisfactorily
accomplished in according with vendors instructions. This finding affected the
procedure quality attribute of the Mitigating Systems cornerstone and is considered
more than minor because if left uncorrected, the finding would become a more
significant safety concern as governor stuffing box internal diameters continued to
increase resulting in additional control valve stem binding issues and associated
TDAFW pump overspeed and failure events. The inspectors determined that the finding
was of very low safety significance (Green) through performance of a Phase 1 SDP in
accordance with IMC 0609, Appendix A, "Significance Determination of Reactor
Inspection Findings for At-Power Situations." Specifically, this finding did not involve a
design or qualification deficiency, represent an actual loss of system or TDAFW pump
safety function, or involve seismic, flooding, or severe weather initiating events. This
finding is related to the cross-cutting aspect of problem identification and resolution in
that Dominion failed to recognize the need to translate appropriate vendor acceptance
criteria into the TDAFW governor control valve maintenance procedure despite receipt
of new vendor requirements in 1999.
Enforcement. Code of Federal Regulations 10 CFR Part 50, Appendix B, Criterion V,
Instructions, Procedures and Drawings, requires, in part, that activities affecting quality
shall be prescribed by documented instructions, procedures, or drawings, of a type
appropriate to the circumstances and shall be accomplished in accordance with these
instructions, procedures, or drawings. Criterion V also requires that instructions,
procedures, or drawings shall include appropriate quantitative or qualitative acceptance
criteria for determining that important activities have been satisfactorily accomplished.
Contrary to the above, prior to January 2006, Dominion failed to ensure that the Unit 3
TDAFW pump governor control valve maintenance procedure, MP 3762AB, Terry
Turbine Control Valve Maintenance, included appropriate acceptance criteria for the
stuffing box internal diameter. In addition, the maintenance procedure did not specify
Enclosure
6
the M&TE required to measure critical dimensions and did not require the recording of
measurements needed to verify the maintenance activity was satisfactorily
accomplished in according with vendors requirements. This issue was determined to
be of very low safety significance (Green) and has been addressed in the licensees
corrective action program as CR-06-02043 and CR-06-02044. Corrective actions
included revising the maintenance procedure to update the clearance values to the
correct values as well as instructing maintenance system team personnel on the event
relative to utilizing the correct MT&E for the work scope. This issue is being treated as
an non-cited violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000423/2005006-02, Failure To Include Acceptance Criteria In Maintenance
Procedures).
.3 Introduction. The inspectors identified a Green NCV of 10 CFR 50, Appendix B,
Criterion III, Design Control associated with the Unit 2 charging system pump
discharge dampener modification. Specifically, the licensees review of the design
modification failed to adequately consider the suitability of the dampener modification in
that a potential common mode failure mechanism associated with gas binding of the
charging pump suction was not considered nor evaluated.
Description. Discharge dampeners were installed on the Unit 2 charging pumps during
the fall 2003 refueling outage. These dampeners consisted of a nitrogen-filled rubber
bladder contained within a pressure vessel for each of the three charging pump
discharge lines. Prior to implementation of the modification, engineers involved in the
design development during May and June 2003 considered the potential for nitrogen
leakage from a failed bladder back through the pumps affecting the common suction
line. However, these concerns were not formally evaluated or addressed in the design
package and its associated safety screening (DM-M2-03006). The safety-related
functions of the Unit 2 charging pumps are to provide RCS Inventory Control and
Reactivity Control during a reactor shutdown.
On December 12, 2005, the licensee identified a small boric acid leak from the cap for
the B charging pump discharge pulsation dampener. The licensee generated
CR 05-13753 to investigate and repair the leak. Dominion incorrectly concluded that the
leakage was not due to a failed bladder in the B pump pulsation dampener and
performed no maintenance. Subsequently, the failure of the B charging pump bladder
released the pulsation dampeners nitrogen charge, which migrated backwards through
B charging pump internal check valves, and accumulated in the common suction
header for the three positive displacement charging pumps.
On January 9, 2006, operators observed erratic charging header flow on the running C
pump. The operators attempted to run the standby charging pumps but observed
similar indications. Shortly thereafter, all pumps were stopped and the system was
declared inoperable. A pump was returned to operation within approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> but
later the same day Unit 2 again lost all charging header flow. Dominion subsequently
determined charging was lost as a result of gas in the suction piping.
Enclosure
7
Following the January 9, 2006 event, the licensee instituted a compensatory measure to
ensure continued charging pump operability (documented in Operability Determination
MP2-001-06). The measure was intended to ensure that a potentially failed bladder on
an idled pump would be isolated before its nitrogen charge could migrate back through
the pump and into the common suction line for all three pumps. Isolation of an idle
pump would thus prevent gas binding a running pump. Based on an engineering
evaluation of A pump performance (NUCENG-06-003), Dominion determined that it
would take a minimum of 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> for nitrogen from a postulated failed A pump
bladder to migrate back through an idle A pump and affect the remaining pumps.
However, a test performed on January 14, 2006, for back leakage through the B
pump, revealed that gas nitrogen migration could occur within 30 minutes of a failure of
the B bladder. The licensee subsequently addressed the difference in back leakage
rates and revised the operability determination and associated compensatory measures
accordingly (CR-06-00471).
The inspectors interviewed selected licensed operators on shift who responded to the
gas binding event. Based on these interviews, the inspectors determined charging
system operating procedures did not provide direction for effective response to gas
binding of the charging pumps in that the alarm response procedure (ARP) was the only
operating procedure (among normal, abnormal, alarm, and emergency procedures) that
implemented the guidance of SOER 97-01. As a result, operator attempts to restore
charging header flow led to gas binding the idle charging pumps. Specifically in 1999, in
response to recommendations in SOER 97-01, Potential Loss Of High Pressure
Injection And Charging Capability From Gas Intrusion, the licensee added a caution to
the charging pump trip ARP for the three charging pumps. The caution directed
operators to consider gas binding prior to starting an additional charging pump.
However, the ARP did not provide explicit guidance for actions necessary to prevent a
common mode failure of all pumps if gas binding was suspected nor did it give operators
guidance for how they could determine whether gas binding had occurred. Further, the
inspectors determined that plant conditions never reached the charging pump trip alarm
setpoint during the January 9, 2006 event; the alarm for low charging header flow
actuated.
Inspectors determined that the licensee had multiple opportunities to develop adequate
procedures for response to a gas-binding event. Dominion Procedure DNAP-3002
required re-evaluation of significant SOERs, which includes SOER 97-01, every two
years. This review provided Millstone at least three previous opportunities (2001, 2003,
and 2005) to upgrade procedures. An opportunity also existed following a March 2003
Unit 2 loss of charging event. Although the March 2003 event prompted Millstone staff
to develop an abnormal operating procedure (AOP) for loss of charging, the procedure
was still under development when the January 2006 loss of charging event occurred.
Analysis. The issue of not considering the potential for common-mode failure
introduced by the design modification was considered a performance deficiency. In
addition, the licensee failed to promptly investigate and repair a degraded bladder
identified in December 2005 on the B charging pump discharge pulsation dampener.
This contributed to the failure of all three charging pumps due to gas binding. However,
Enclosure
8
since the design modification preceded the failure to repair a degraded bladder, it was
considered the root cause of the issue.
This issue is greater that minor because it resulted in the failure of one or more charging
pumps and adversely impacted the systems emergency boration and high pressure
injection mitigation capability and availability. This finding adversely impacted the
Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Based upon the IMC 0609, Phase 1 screening worksheets, this finding
required a Phase 2 evaluation due to the finding representing a loss of system safety
function. Based upon the information gathered by the inspectors, the assumed charging
pump unavailability times due to gas binding were: B charging pump inoperable from
December 12, 2005 to January 9, 2006 (672 hours0.00778 days <br />0.187 hours <br />0.00111 weeks <br />2.55696e-4 months <br />); C charging pump inoperable for
approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (total); and A charging pump inoperable for approximately 12
hours (total). The inspector performed a Phase 2 evaluation using the Risk-Informed
Inspection Notebook for Millstone Unit 2. Based upon the results of the Phase 2
evaluation indicating a potentially greater than Green risk significance, the Region I
Senior Reactor Analyst (SRA) conducted a Phase 3 evaluation.
The SRA used the Millstone 2 Standardized Plant Analysis Risk (SPAR) Model,
Revision 3.21, to evaluate this finding. Assuming the above stated charging pump
unavailability times for the three charging pumps, the cumulative increase in core
damage probability for this condition was determined to be in the low E-8 range (very
low safety significance). The dominant core damage sequences involves steam
generator tube rupture initiating events and the failure of operators to properly isolate
the faulted steam generator and depressurize the reactor. The availability of the safety
injection pumps as an alternative high pressure injection source mitigated the
consequences of the charging pumps being unavailable.
This finding has a problem identification and resolution cross-cutting aspect in that
evaluations and corrective actions performed by the licensee were inadequate to
prevent charging system anomalies despite the identification of a small boric acid leak
from the cap of the B charging pump discharge pulsation dampener, an indication of a
failed pulsation dampener for which no corrective maintenance was performed.
Enforcement. Code of Federal Regulations 10 CFR 50, Appendix B, Criterion III,
Design Control, requires, in part, that measures shall be established for the selection
and review of the suitability of application of equipment essential to the safety-related
function of components. Contrary to this requirement, Dominion failed to adequately
consider the suitability of the dampener modification in that during May and June 2003,
a potential common mode failure, gas binding of the charging pump suction, was not
fully considered or evaluated. This issue was determined to be of very low safety
significance (Green) and has been addressed in the licensees corrective action
program as CR-06-02382. Corrective actions include performing a root cause to, in
Enclosure
9
part, determine why the design process and other organizational factors that installed
the bladders did not identify the potential common mode failure. This issue is being
treated as a non-cited violation consistent with Section VI.A of the Enforcement Policy
(NCV 05000336/2006006-03, Inadequate Suitability of Application Evaluation for
Dampener Modification)
In addition to the three green findings mentioned above, the inspectors identified two
findings which were determined to be violations of minor significance and are not
subject to enforcement action in accordance with the NRCs enforcement policy. The
first minor finding was associated with the licensee failure to retain quality assurance
records as required by 10 CFR 50, Appendix B, Criterion XVII, Quality Records.
Specifically, corrective maintenance was performed on safety-related valve
3CDS*CTV40, a Chill Water Return Containment Isolation valve, and no maintenance
records were retained for this activity. The maintenance consisted of adjusting an
actuator stop screw following a failed surveillance valve stroke test, and was performed
as minor maintenance which did not require record retention. The second minor finding,
pertinent to the same issue, involved the licensee utilization of the minor maintenance
process for this work. The licensees procedure MP-20-WP-GDL10, Work
Identification, Screening, Prioritization, and Process Selection, stated that maintenance
activities requiring post-maintenance testing are not eligible candidates for minor work.
In light of this requirement, the maintenance mentioned above (which consisted of
adjusting the actuator stop screw), was performed as minor maintenance. This
constituted a minor violation of Technical Specification 6.8.1 in that the licensee failed to
follow the procedure requirement mentioned above.
.2 Prioritization and Evaluation of Issues
a. Inspection Scope
The inspectors reviewed the CRs listed in the attachment to this report to assess
whether the licensee adequately prioritized and evaluated problems. These reviews
evaluated the causal assessment of each issue (i.e., root cause analysis or apparent
cause evaluation); and for significant conditions adverse to quality, the extent of
condition, and determination of corrective actions to preclude recurrence. Throughout
the inspection, the inspectors attended periodic meetings to observe the CR review
process and to understand the basis for assigned significance and root cause levels.
The inspectors also considered risk insights from the Millstone probabilistic risk
assessment to help focus the inspection sample. The inspectors selected the Unit 2
charging system for an expanded review of five years. This system was selected
because of long standing and ongoing performance issues associated with the system
that were revealed in a loss of charging system event that occurred on January 9, 2006.
The inspectors selected a sample of CRs associated with previous NRC NCVs and
findings to determine whether the licensee evaluated and resolved problems associated
with compliance to applicable regulatory requirements and standards. The inspectors
Enclosure
10
reviewed the licensees approach to operating experience (OE), which included an
assessment of multiple examples of how effectively OE is used. Operability and
reportability determinations associated with CRs were also reviewed.
b. Assessments
The inspectors determined that the licensee, adequately prioritized and evaluated the
issues and concerns entered into the CAP. The inspectors concluded that prioritized
CRs were based on the safety significance of the issue. Operability determinations and
reportability assessments were made promptly once issues were entered into the CAP.
The inspectors noted that licensee management was thoroughly prepared during CR
screening meetings as evidenced by their probing questions of presenters. Evaluations
were generally completed in a timely manner, particularly after the CAP process was
revised to establish a standard 30-day deadline for all CR evaluations. Clear guidance
has been developed for performing cause evaluations, and multi-level reviews of
completed evaluations has resulted in generally high quality evaluations with proposed
corrective actions that addressed the identified causes.
The inspectors, however, noted performance deficiencies for a condition adverse to
quality associated with the Unit 3 turbine-driven auxiliary feedwater (AFW) governor
control valve. Following an AFW overspeed trip event that occurred in April 2005, a
degraded condition was identified and entered into the licensees corrective action
program although an engineering evaluation was not performed nor documented at that
time. Prior to this inspection, operability had still not been evaluated as required in
accordance with the stations operability assessment processes. An operability
evaluation, however, was performed when this deficiency was identified by the
inspectors and acknowledged by the licensee.
c. Findings
.1 Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Action, for the failure to take effective corrective
action to prevent a repeat failure of the Unit 3 TDAFW pump. On April 17, 2005, the
TDAFW pump tripped on overspeed following an inadvertent reactor trip and safety
injection. On January 9, 2006, the TDAFW pump tripped again on overspeed during a
routine quarterly surveillance test. The inspectors determined that both events were
associated with mechanical stem binding of the TDAFW pump governor control valve.
Description. On April 17, 2005, following an inadvertent reactor trip and safety injection
actuation, the TDAFW pump tripped on overspeed. The preliminary cause of the failure
was determined to be stem binding of the governor control valve (see NRC Inspection
Report 05000423/2005012, Section 2.2). During overhaul of the governor control valve,
the licensee found that the stuffing box was worn away internally allowing the spacers
and washers housed in the stuffing box to move excessively. This condition was
entered into the CAP as CR-05-04012. In addition, maintenance personnel also
questioned whether the gap between the stuffing box inner diameter (ID) and the
stainless steel washers outer diameter (OD) was acceptable. The licensee contacted
Enclosure
11
the vendor and discussed these issues. As a result, the spacers and packing were
replaced, however, the stuffing box condition was not repaired nor further evaluated.
Following replacement of the governor control valve stem and packing, a satisfactory
post-maintenance and surveillance test were performed. The TDAFW pump was
declared operable on April 22, 2005.
On January 9, 2006, the TDAFW pump tripped again on overspeed during a routine
quarterly surveillance. The plant entered a 72-hour technical specification action
statement (TSAS) and the licensee formed a root cause evaluation team to investigate
this event. The licensee originally attributed the cause to be excess condensate in the
supply lines to the TDAFW pump. However, subsequent to the trip, the absence of
condensate in the supply lines was verified by ultrasonic inspection. On January 10,
2006, the licensee performed the surveillance again with the same results, the TDAFW
pump tripping on overspeed. After the second failed surveillance test, the licensee
performed a maintenance run in an effort to further evaluate the TDAFW pump
performance. During the maintenance run, maintenance personnel noted that the
control valve movement was sluggish and exhibited indications of sticking. Maintenance
personnel performed a valve stem motion test and observed stem binding during
specific portions of the stem travel. As a result, maintenance personnel cleaned burrs
from rough areas on the stem. Another surveillance test was performed and the
TDAFW pump tripped on overspeed for the third time. Mechanics disassembled the
governor control valve and replaced the governor. Subsequent vendor testing showed
no problems or concerns with the governor performance. The licensee re-assembled
the control valve with a new stem and new packing. During the refurbishment process,
mechanics found that the cam on the governor control valve was worn and not smooth.
The cam plate was ground clean and confirmed to have free movement throughout the
entire range. The governor control valve was fully reassembled and a final operability
run performed successfully on January 12, 2006.
The inspectors reviewed the licensees root cause evaluation (RCE) associated with the
April 2005 and January 2006 events; conducted interviews with RCE inspectors
members and system engineers; and reviewed associated work orders and conditions
reports. Based on the above, the inspectors concluded that the April 2005 TDAFW
pump overspeed trip and the January 2006 overspeed trip were due to stem binding of
the governor control valve. Specifically, the inspectors reviewed the technical manual
associated with the TDAFW governor control valve and determined that the stuffing box
internal dimension exceeded the value required by the vendor. On April 12, 1999, the
licensee incorporated vendor guidance for the TDAFW pump governor control valve
under design change notice (DCN) DM3-01-0046-99. This DCN provided vendor
requirements in response to an industry issue associated with terry turbine governor
control valve stem binding. Specifically, Section 8.3, paragraph 7, of the vendor
technical manual directed verification of the dimensional adequacy of the governor valve
components, referring to the critical fits and dimensions defined in Section 8.6 of this
guide. The as-found ID of the stuffing box (1.080 to 1.098 inches) exceeded the
required dimension (1.005 inches) as stated in Section 8.6 of the vendors technical
manual. The January 9, 2006, RCE inspectors determined that the governor control
stuffing box wear was a contributing cause to the January 9, 2006, TDAFW pump
Enclosure
12
overspeed trip. Stuffing box wear can accelerate packing wear, which leads to spacing
problems and stem binding.
Additionally, the inspectors noted that following completion of the January 2006 RCE,
the licensee did not formally disposition the stuffing box degraded condition in
accordance with station procedures. Specifically, following the January 2006 RCE
teams identification that the degraded stuffing box was a contributing cause of the
January 2006 TDAFW pump failure, the licensee did not write a condition report and
inform the shift manager as required by DNAP-1408, Dominion Operability
Determination Program, and RP 5, Operability Determinations. The inspectors
discussed this with the licensee and as a result, CR-06-02039 was generated, as well as
a Reasonable Expectation of Continued Operability (RECO) to address operability
concerns associated with this issue. The licensees immediate corrective actions for this
issue included repacking of the TDAFW pump governor control valve and repair of the
cam plate. Additionally, the licensee planed to conduct a repair of the stuffing box within
three months of the January 9, 2006, TDAFW pump failure and replace the stuffing box
when parts became available.
Analysis. The performance issue associated with this finding is that the licensee failed
to take effective corrective action to prevent a repeat failure of the Unit 3 TDAFW pump
associated with governor control valve stem binding issues. Specifically, the licensee
failed to fully evaluate and correct discrepancies associated with the governor control
valve stuffing box discovered in April 2005 which was subsequently determined to be a
contributing cause to the January 2006 TDAFW pump overspeed trip.
This finding is more than minor because it is associated with the Mitigating Systems
cornerstone and affects the objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Specifically, because the degraded stuffing box was not corrected, the
reliability of the TDAFW pump was adversely affected. The inspectors evaluated this
finding in accordance with IMC 0609, Appendix A, Significance Determination of
Reactor Inspection Findings for At-Power Situations. Based on the last successful
TDAFW pump run on December 1, 2005, and the failure on January 9, 2006, (a time
period of approximately 39 days), the calculated fault exposure time was 19.5 days. In
evaluating this finding, the Significance Determination Process (SDP) Phase 1
screening identified that a SDP workbook Phase 2 evaluation was needed because the
TDAFW pump was potentially inoperable in excess of its Technical Specification
Allowed Outage Time of three days. Since the Phase 2 evaluation exceeded a risk
threshold, an NRC Region I Senior Reactor Analyst (SRA) conducted a Phase 3
evaluation to more accurately account for the exposure time. Using the site specific
Millstone Standardized Plant Analysis Risk (SPAR) Model, Revision 3.11, the SRA
evaluated this finding and determined it to be Green since (due to the specific trip and
throttle valve and governor valve reset characteristics and existing procedures) credit
was given for recovery of the TDAFW pump during subsequent restart attempts that
would be reasonably expected to occur during design basis events. This finding is
related to the cross-cutting area of problem identification and resolution in that the
licensee did not fully evaluate and correct an identified degraded condition.
Enclosure
13
Enforcement. Code of Federal Regulations 10 CFR Part 50, Appendix B, Criterion XVI,
Corrective Action, requires, 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 non-conformances are promptly identified and
corrected. In the case of significant conditions adverse to quality, the measures shall
assure that the cause of the condition is determined and corrective action taken to
preclude repetition. Contrary to the above, following identification and documentation of
excessive Unit 3 TDAFW pump internal stuffing box wear in April 2005, the licensee
failed to fully evaluate and understand this condition which was later documented as a
contributing cause to a recurring overspeed trip failure that occurred on January 9,
2006. This issue has been entered in the licensees corrective action program as
CR 06-00244. Corrective actions for this issue included repacking of the TDAFW pump
governor control valve, repair of a cam plate, and plans to conduct a stuffing box repair
within three months of the January 2006 pump failure. This issue is being treated as a
non-cited violation consistent with Section VI.A of the Enforcement Policy (NCV 05000423/2006006-04, Failure to Evaluate and Correct Condition Adverse to
Quality Associated with TDAFW Pump).
.3 Effectiveness of Corrective Actions
a. Inspection Scope
The inspectors reviewed the corrective actions associated with selected CRs to
determine whether they addressed the identified causes of the problems. The
licensees timeliness in implementing corrective actions and their effectiveness in
precluding recurrence for significant conditions adverse to quality were also reviewed.
Furthermore, the inspectors assessed the backlog of outstanding corrective actions to
determine if they, individually or collectively, represented an increased risk to the plant.
The inspectors also reviewed NCVs and findings issued since the last inspection of the
licensees CAP to determine if issues placed in the program had been properly
evaluated and corrected.
b. Assessments
Overall, the inspectors concluded that the licensees corrective actions for identified
deficiencies were typically implemented in a timely and adequate manner.
Administrative controls were implemented to ensure that corrective actions were
completed as scheduled, and reviews were performed to ensure that actions were
implemented as intended. The licensee also conducted in-depth effectiveness reviews
for significant issues to determine if the corrective actions were effective in resolving
specific issues. The licensee appropriately self-identified ineffective or improper
closeout of corrective actions and re-entered the issue into the CAP for further action.
The inspectors, however, identified one example where the licensees implementation of
corrective actions was inadequate. This involved ineffective correction actions
associated with repetitive local leak rate testing (LLRT) failures on a safety-related
Enclosure
14
containment penetration isolation valve associated with the Unit 3 Reactor Plant Chilled
Water System.
c. Findings
.1 Introduction. A Green NCV of 10 CFR 50, Appendix B, Criterion XVI Corrective Action
was identified for ineffective corrective actions associated with repetitive failures of local
leak rate testing of the Unit 3 Reactor Plant Chilled Water System (CDS) inboard
containment isolation valve, 3CDS*CTV40A. This represented a loss of redundancy
and reduced reliability of the containment.
Description. In February 2001, during the performance of procedure SP 3612B.4, Type
C LLRT - Penetration No. 116 (I) [3CDS*CTV40A], valve 3CDS*CTV40A failed its
LLRT. The licensee adjusted the valve actuator stop screw and successfully retested
the valve. In April 2004, when the licensee performed an LLRT on 3CDS*CTV40A, it
again failed its test. For a second time the licensee adjusted the valve actuator stop
screw and obtained a satisfactory retest. A third LLRT failure occurred in October 2005
further demonstrating that corrective actions previously taken were ineffective.
The inspectors determined that after the second failure in April 2004, the licensee did
not effectively identify the repetitive nature of the failure and the corrective actions taken
were not sufficient to prevent repetitive failures. Specifically, the licensee did not
determine what caused the actuator stop screw to continue to require adjustment nor
did they assess the internal condition of the valve to ascertain whether something
internal to the valve was contributing to the LLRT failures. As a result, the actions taken
failed to correct the cause of the test failures.
Analysis. The performance deficiency associated with this issue is the failure to
implement adequate corrective actions to repair valve 3CDS*CTV40A. Specifically,
following the failure that occurred in April 2004, which constituted a repetitive failure for
the same component, the licensee failed to identify the cause of the repetitive failure.
As a result, adequate corrective actions were not implemented. Traditional enforcement
does not apply because there were no actual safety consequences or impacts on the
NRCs ability to perform its regulator function, or willful aspects to the violation.
However, this issue is more than minor because it is associated with the Barrier Integrity
Cornerstone attribute of SSC/Barrier Performance - containment isolation SSC
reliability. Unacceptable leakage past this valve resulted in a decrease in operational
capability of the containment isolation system and a decrease in reliability of
containment isolation SSCs. In accordance with the Reactor Safety SDP, a Phase 2
analysis of this condition was performed using IMC 0609, Appendix H, Containment
Integrity Significance Determination Process. Specifically, this issue did not represent
an actual open pathway in the physical integrity of reactor containment or an actual
reduction of the atmospheric pressure control function of the reactor containment.
Therefore, the risk of this finding was determined to be of a very low safety significance
(Green). This finding is related to the cross-cutting area of problem identification and
resolution in that the licensee did not implement effective corrective actions to prevent a
recurring component failure.
Enclosure
15
Enforcement. Code of Federal Regulations 10 CFR 50, Appendix B, Criterion XVI,
Corrective Action, requires, in part, that conditions adverse to quality, such as failures,
are promptly identified and corrected. Contrary to this requirement, the licensee did not
take corrective actions to address repetitive failures of the Unit 3 Reactor Plant Chilled
Water System inboard containment isolation valve, 3CDS*CTV40A, following February
2001, April 2004, and October 2005 local leak rate test failures. This issue was
determined to be of very low safety significance (Green) and has been entered in the
licensees corrective action program as CR 05-10651, a condition report which
documented a licensee action to create a plan to resolve the failures. This issue is
being treated as a non-cited violation, consistent with Section VI.A of the Enforcement
Policy (NCV 05000423/2006006-05, Failure To Implement Effective Corrective
Actions Associated With Repetitive LLRT Failures)
.4 Assessment of Safety Conscious Work Environment
a. Inspection Scope
During the interviews with station personnel, the inspectors assessed the safety
conscious work environment at the Millstone station. Specifically, the inspectors
assessed whether people were hesitant to raise safety concerns to their management
and/or the NRC. The inspectors reviewed Millstones Employee Concerns Program
(ECP) to determine if employees were aware of the program and had used it to raise
concerns. The inspectors also discussed selected issues with the ECP manager and
engineering department management to compare insights from the inspection with
Millstones reviews.
b. Findings and Assessments
No findings of significance were identified.
The inspectors determined that personnel are willing to raise issues, and that there was
no direct evidence of an unacceptable work environment. All of the personnel
interviewed had an adequate knowledge of the CAP and ECP. No employees indicated
that they personally would not raise a concern.
4OA6 Meetings, Including the Exit Meeting
The inspectors presented the inspection results to Mr. Alan Price and other members of
licensee management on March 3, 2006. Licensee management acknowledged the
results presented. No proprietary information was identified during the inspection.
4OA7 Licensee-Identified Violations
None.
Enclosure
16
ATTACHMENT: Supplemental Information
In addition to the documentation that the inspectors reviewed (listed in the attachment), copies
of information requests given to the licensee are in ADAMS, under accession number
Enclosure
A-1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
H. Beeman, System Engineer
A. Campbell, Manager Nuclear Protection Services
J. Chadbourne, Unit 2, CVCS System Engineer
G. Closius, Licensing Engineer
C. Dempsey, Manager Nuclear Maintenance
D. Dodson, Supervisor - Licensing
D. Dougherty, System Engineer
E. Dundon, System Engineer
C. Fortune, Unit 2, Component Engineer
R. Griffin, Acting Director - Operations and Maintenance
P. Grossman, Manager Nuclear Engineering
D. Guarneri, System Engineer
S. Heard, Manager Nuclear Oversight
W. Hoffner, Manager Nuclear Operations
M. Jalbert, System Engineer
K. Kirkman, Operations Support
J. Kunze, Unit 2, Operations Manager
J. Langan, Manager Nuclear Site Engineering
R. MacManus, Director - Engineering
M. Marino, Engineer, Condition Based Maintenance
G. McGovern, Supervisor Nuclear Engineering
D. McNeil, System Engineering
D. Pantalone, Unit 2, Operations Training Instructor
F. Perkins, System Engineer
A. Price, Site Vice President
R. Rogozinski, Nuclear Engineer
W. Saputo, Unit 2, System Engineering
S. Scace, Director - Safety and Licensing
R. Schonenberg, System Engineer
P. Strickland, Unit 2 Shift Manager
J. Themig, Unit 2, Computer Support
A. Vomastek, Employee Concerns Program Specialist
V. Wessling, Supervisor Nuclear Corrective Actions
B. Willkens, Manager Nuclear Organizational Effectiveness
Enclosure
A-2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000336/423/2006006-01 NCV Failure to Perform Evaluations on Boric Acid Leaks
(Section 4OA2.1.c.1)05000423/2005006-02 NCV Failure To Include Acceptance Criteria In Maintenance
Procedures (Section 4OA2.1.c.2)05000336/2006006-03 NCV Inadequate Suitability of Application Evaluation for
Dampener Modification (Section 4OA2.1.c.3)05000423/2006006-04 NCV Failure to Evaluate and Correct Condition Adverse to
Quality Associated with TDAFW Pump (Section
4OA2.2.c.1)05000423/2006006-05 NCV Failure To Implement Effective Corrective Actions
Associated With Repetitive LLRT Failures (Section
4OA2.3.c.1)
LIST OF DOCUMENTS REVIEWED
Procedures
C MP 797, Valve Packing, Rev 0
CS-2.13, Rev 3, Process Computer Database Changes
CS-5.03, Rev 4, Plant Process Computer PPC Development / Implementation Guidelines for
Script, Software, Display and Database Changes
DNAP 1004, BACC Program, Rev 3
DNAP-0104, Dominion Nuclear Self-Assessment Program, Rev 001
DNAP-1408, Dominion Operability Determination Process, Rev 008
DNAP-1604, Cause Evaluation Program, Rev 3
DNAP-1604, Cause Evaluation Program, Rev 003
DNAP-2000, Dominion Work Management Process, Rev 004
DNAP-2001, Equipment Reliability Process, Rev 004
DNAP-3002, Dominion Nuclear Operating Experience (OE) Program, Rev 0
EOP 35 ECA-0.0, Loss Of All AC Power, Rev 020
EOP-35 FR-H.1, Response To Loss Of Secondary Heat Sink, Rev 016-01
MP-24-BACC-FAP01, BACC Outage Inspections, Rev 1
MP-20-OM-GDL01, Forced Outage Management Guideline, Rev 2
MP-24-BACC-SAP01, BACC On-line Examinations, Rev 0
MP-24-BACC-FAP02, BACC Initial Refueling and Forced Outage Inspections, Rev 0
MP-24-BACC-PRG, BACC Program, Rev 1
MP-14-OPS-GDL400, Operations Administrative Procedures
MP-14-OPS-GDL400, Rev. 006, Operations Administrative Procedures
MP-16-CAP-FA01.2, Corrective Action Department Responsibilities, Rev 005
MP-16-CAP-FAP01.1, Condition Report Screening and Review, Rev 008
A-3
MP-16-CAP-FAP01.1, Condition Report Screening and Review, Rev 8
MP-16-CAP-FAP01.3, ACR/CR Owner, Action, Owner/Investigator Responsibilities, Rev 009
MP-16-CAP-GDL01, Station Trending, Rev 003
MP-16-CAP-GDL01, Station Trending, Rev 3
MP-16-CAP-SAP01, Condition Report Initiation, Rev 002
MP-16-MMM, Organizational Effectiveness, Rev 010
MP-20-WP-GDL10, Work Identification, Screening, Prioritization, Classification, and Process
Selection, Rev 010
MP-20-WP-GDL30, Work Performance
MP-24-MR-FAP750, Maintenance Rule Scoping, Rev 000-03
MP-PROC-OPS-SP3610A.3-001, RHR System Venting and Valve Line-Up - Train A, Rev 006
MP-PROC-OPS-SP3610A.3, RHR System Vent and Valve Line-Up Verification, Rev 007
OP 2304E, Rev. 015-05, Charging Pumps
OP 3322, Auxiliary Feedwater, Rev 020-02
OP 3310A, RHR System, Rev 016-07
OP2326A52, B RBCCW Heat Exchanger Maintenance Facility 1 and 2, Rev 000-00
OP2353B, Filling Venting Boric Acid CVCS Piping Components, Rev 001-02
OP3304A, Charging and Letdown, Rev 029-06
OP3314F, Control Building Heating Ventilation Air Conditioning and Chill Water, Rev -020-03
OP3330C, Reactor Plant Chill Water, Rev 008-07
OP3330D, Charging Pump Cooling, Rev 006-04
RAC 12, Rev. 005-01, 50.59/72.48 Screens and Evaluations
SP 2664, Rev. 000-00, Charging Pump Pulsation Dampener Test
SP 2664, Rev. 000-03, Charging Pump Pulsation Dampener Test
SP 2664, Rev. 001-05, Charging Pump Pulsation Dampener Test
Audits and Self-Assessments
Dominion Problem Identification and Resolution at Millstone Power Station, dated 1/20/06
Audit 04-13, Environmental Management System (Millstone), dated 11/17/04
Audit 04-12, Nuclear Materials, dated 11/5/04
Audit 04-15, Dominion Oversight Evaluation, dated 9/29/04
Audit 05-06, RP/PCP/CHEM Programs, dated 9/22/05
Audit 05-08, Nuclear Training and Qualifications, dated 11/21/05
Audit 04-08, Radiation Protection & Process Control Programs, dated 9/20/04
Audit 04-07, Corrective Actions, dated 8/4/04
Audit 04-05, Technical Training, dated 5/25/04
Audit 04-10, Document Control, Records, and Procedures, dated 11/3/04
Audit 04-11, Measuring and Test Equipment (Millstone)
Audit 05-038, Operational Configuration Control, dated 12/9/05
Audit 05-03, Operational Alignment, dated 3/17/05
Audit 05-43, Assessment of Station Emergency Response Organization actions for the U3 Alert
Declared on 4/17/05
Audit 05-17, Operator Training Program Comprehensive Self-Evaluation, dated 8/11/05
Audit 05-04, Impact of Training on Performance of Supplemental Personnel, dated 6/2/05
Audit 05-02, Shift Technical Advisor Training Program Implementation and Effectiveness, dated
3/14/05
Enclosure
A-4
Audit 04-37, Operational Decision-Making Process, dated 12/17/04
Audit 04-14, Operator Training Initial Training Program Effectiveness, dated 6/24/04
Audit 04-21, Fire Brigade Record keeping Overview, dated 8/25/04
Audit 04-10, Millstone 3R09 Refueling Outage Readiness, dated 3/31/04
Audit 04-04, Fire Protection Implementation, 05/27/04
Audit 04-09, Design Control and Engineering Programs, 09/22/04
Audit 04-16, Millstone ISFSI, 03/28/05
Audit 05-04, Fire Protection QA Program, 05/24/05
MP-SA-02-059, Generic Letter 88-05 Commitment Effectiveness, 06/28/02
MP-SA-04-01, System Engineering Implementation of Performance, Monitoring, and Trending
Plans, 02/18/04
MP-SA-05-09, Effectiveness of Engineering Quality Review Inspectors, 07/01/05
MP-SA-05-26, System Health Report, 01/05/06
Operating Experience Documents Reviewed
SOER 97-1, Potential Loss of High Pressure Injection and Charging Capability from Gas
Intrusion, dated November 28, 1977
Non-Cited Violations (NCV) and Findings (FIN)
NCV 05000336/2004002-01, Failure to Implement Adequate Design Control and Suitably Test
a Modification to the Charging System
NCV 05000336/2004002-02, Failure to Correct Safety Injection Tank Leakage
NCV 05000336/2004005-01, Failure to adequately implement procedures for steam generator
feed pump testing which led to a reactor trip
NCV 05000423/2004005-03, Failure to implement post maintenance testing to identify
improperly performed valve repairs on instrument air dryer system
NCV 05000336/2004005-04, Failure to adequately implement vendor technical manual
requirements into written procedures which control the alignment and operation of electrical
power sources to vital shutdown cooling components
NCV 05000423/2004006-01, Inadequate corrective actions to prevent repetitive failures of the
QSS and RSS containment isolation check valves
NCV 05000336/2004006-03, Failure to adequately implement procedures for draining the RCS
NCV 05000336/2004007-03, Failure to properly establish and implement 10 CFR 50, Appendix
B, Criterion XVI, to address repeated lifting of Main Steam
Code Safety Valves
NCV 05000336/2004007-04, I&C technicians and operations personnel did not verify all
appropriate prerequisites or perform all applicable procedural steps which then resulted in the
inadvertent actuation of a safety-related system
NCV 05000423/2004007-07, Failure to Properly Implement TS 3.8.3.2, Onsite Power
Distribution - Shutdown
NCV 05000423/2004007-08, Dominion failed to establish precautions and prerequisites to
prevent plant configuration changes that could lead to air entrainment in the RHR system
FIN 05000336/2004008-03 NCV High Concentration of Airborne Radioactive Material During
Filter Transfers
FIN 05000336/2005002-01, Failure to adequately address concerns related to freeze protection
Enclosure
A-5
of an outdoor temporary instrument air compressor
NCV 05000423/2005002-02, Failure to promptly evaluate and correct a degraded condition
associated with the divider plate for all three RPCCW HXs
NCV 05000423/2005002-03, Failure to adequately implement testing procedures for restoring
the A EDG to service
NCV 05000423/2005002-04, Failure to adequately perform post-maintenance testing on
hydrogen recombiner
NCV 05000336/2005002-05, Failure to implement procedures to correctly install temporary
cooling to the East 480 volt switchgear
NCV 05000423/2005002-06, Failure to take prompt corrective actions to determine the extent
of condition of air trapped in the RHR suction and discharge piping
NCV 05000423/2005003-01, Failure to evaluate exceeding specified fire loading limit for Main
Steam Valve Enclosure
NCV 05000336/2005004-01, Failure to take TS action with the B EDG inoperable
FIN 05000336,423/2005004-02, Failure to adequately implement operability determination
procedure on three occasions
NCV 05000423/2005004-03, Failure to properly correct known water in-leakage into the B
EDG rocker arm lubricating oil system
NCV 05000423/2005012-01, Failure to Implement Appropriate PMs on the TDAFW
Pump Control Valve
FIN 05000423/2005012-03, Improper Event Diagnosis led to E-plan Declaration
NCV 05000423/2005012-04, EOP E-0 Step not performed as required
NCV 05000423/2005012-05, Simulator response did not adequately model MSSV response
NCV 05000423/2005012-06, False or Misleading Control Room Indications
NCV 05000423/2005012-07, Less than adequate corrective actions for potential RCS pressure
boundary degradation due to boric acid corrosion
Condition Reports (* designates CRs that were generated due to issues identified by the
inspectors)
CR-01-10310 CR-04-02446 CR-04-05733 CR-04-08341 CR-04-10102 CR-05-01233
CR-02-07071 CR-04-02514 CR-04-05384 CR-04-08342 CR-04-10105 CR-05-01281
CR-02-11761 CR-04-02532 CR-04-05822 CR-04-08471 CR-04-10129 CR-05-01767
CR-03-02416 CR-04-03130 CR-04-05857 CR-04-08487 CR-04-10268 CR-05-03354
CR-03-04924 CR-04-03205 CR-04-06166 CR-04-08661 CR-04-10535 CR-05-03527
CR-03-08781 CR-04-03272 CR-04-06419 CR-04-08662 CR-04-10678 CR-05-03723
CR-03-09341 CR-04-03329 CR-04-06464 CR-04-08663 CR-04-10697 CR-05-03735
CR-03-12593 CR-04-03411 CR-04-06473 CR-04-08664 CR-04-10741 CR-05-04113
CR-04-01129 CR-04-03611 CR-04-06608 CR-04-08741 CR-04-10903 CR-05-04124
CR-04-01228 CR-04-03704 CR-04-06615 CR-04-08779 CR-05-00100 CR-05-04127
CR-04-01565 CR-04-03781 CR-04-07015 CR-04-08817 CR-05-00169 CR-05-04129
CR-04-01647 CR-04-03886 CR-04-07144 CR-04-09306 CR-05-00399 CR-05-04130
CR-04-01675 CR-04-04092 CR-04-07158 CR-04-09450 CR-05-00449 CR-05-04132
CR-04-01858 CR-04-04219 CR-04-07402 CR-04-09768 CR-05-00768 CR-05-04133
CR-04-02121 CR-04-04549 CR-04-07405 CR-04-09890 CR-05-00922 CR-05-04135
CR-04-02228 CR-04-04808 CR-04-07836 CR-04-09913 CR-05-00953 CR-05-04136
CR-04-02255 CR-04-05283 CR-04-08130 CR-04-10101 CR-05-01147 CR-05-04138
Enclosure
A-6
CR-05-04139 CR-05-09162 CR-05-04998 CR-05-10651 CR-05-12702 CR-06-01330
CR-05-04141 CR-05-10257 CR-05-05122 CR-05-10837 CR-05-12756 CR-06-01635*
CR-05-04154 CR-05-01213 CR-05-05405 CR-05-11043 CR-05-12876 CR-06-01720*
CR-05-04701 CR-05-01281 CR-05-05660 CR-05-11318 CR-05-12877 CR-06-01969*
CR-05-05078 CR-05-01764 CR-05-06640 CR-05-11385 CR-05-12923 CR-06-01989*
CR-05-05976 CR-05-01767 CR-05-07916 CR-05-11413 CR-05-13007 CR-06-01996*
CR-05-06386 CR-05-01796 CR-05-08048 CR-05-11468 CR-05-13474 CR-06-02037*
CR-05-06461 CR-05-03177 CR-05-08252 CR-05-11515 CR-05-13709 CR-06-02039*
CR-05-06982 CR-05-03734 CR-05-08549 CR-05-11544 CR-05-13781 CR-06-02043*
CR-05-06990 CR-05-03926 CR-05-08649 CR-05-11652 CR-05-13342 CR-06-02044*
CR-05-07367 CR-05-04216 CR-05-08829 CR-05-11711 CR-05-13354 CR-06-02067*
CR-05-07753 CR-05-04330 CR-05-09073 CR-05-11811 CR-05-13356 CR-06-02088*
CR-05-08141 CR-05-04331 CR-05-09181 CR-05-12414 CR-06-00233 CR-06-02125*
CR-05-08163 CR-05-04332 CR-05-09254 CR-05-12492 CR-06-00243 CR-06-02128*
CR-05-08322 CR-05-04633 CR-05-10015 CR-05-12544 CR-06-00244 CR-06-02136*
CR-05-08722 CR-05-04663 CR-05-10183 CR-05-12594 CR-06-00439 CR-06-02382*
CR-05-09137 CR-05-04667 CR-05-10322 CR-05-12650
Maintenance Orders
M2-04-11373 M3 0515982 M3 0402293 M3 0507226 M3 0515410 M3-05-13077
M2-05-07211 M3 0515412 M3 0405217 M3 0507233 M3-01-02534 M3-05-16571
M3 0406795 M3 0515411 M3 9707226 M3 0514896 M3-04-06500 M3-06-00715
M3 0515983 M3 0119266 M3 0410662
Maintenance Rule Documents:
Maintenance Rule (a)(1) Evaluation for the Unit 3 Service Water System, The Service Water
System is (a)(1) for Function 1.01 for Piping Failures, Rev 5
Maintenance Rule (a)(1) Evaluation for the Unit 2 Service Water System, The Service Water
System is (a)(1) due to Exceeding Performance Criteria 4a, Rev 1
Maintenance Rule (a)(1) Evaluation for the Unit 3 Service Water System, The Service Water
System is (a)(1) for Function 1.01 for Strainer Failures, Rev 2
Maintenance Rule (a)(1) Evaluation for the Unit 3 Containment Isolation System, The
Containment Isolation System is (a)(1) for Function 1.01c, Rev 1
Miscellaneous
Just In Time PM review 0619-008
Just In Time PM review 0619-003
Just In Time PM review 0619-002
Just In Time PM review 0619-011
Just In Time PM review 0619-009
Just In Time PM review 0619-010
Just In Time PM review 0619-004
Just In Time PM review 0619-012
Just In Time PM review 0619-006
Enclosure
A-7
PM Change and Deferral Request, 2000-1278
PM Change and Deferral Request, 2003-0663
PM Change and Deferral Request, 2004-0133
PM Change and Deferral Request, 2004-0465
PM Change and Deferral Request, 2003-0662
Technical Evaluation M3-EV-05-0028, Rev 0, Summary of Events and Actions Taken
Pertaining to Discovery of Jacket Water in the B EDG Rocker Lube Oil System, Between April
2005 and September 27, 2005", October 19, 2005
Technical Evaluation M3-EV-01-0035, Rev 0, Millstone Unit 3 Service Water System Air
Binding at the Auxiliary Building Booster Pumps, January 2002
Technical Evaluation for Precharge Requirements for MP2 Charging Pump Dampener Bladders
M2-EV-04-0009
Technical Evaluation for MP2 Charging Pump Discharge Pulsation Dampener and Relief Valve
Discharge Routing Evaluation M2-EV-03-0029
Design Modification DCR M2-03006, MP2 Charging Pumps P-18A, P-18B, and P-18C Pulsation
Dampeners
Design Change Notice DM2-02-0306-03, Pre-Charge Pressure of Pulsation Dampeners
Contingency
Control Room Logs for 1/9/06-1/10/06
Memorandum, Subject: Millstone Unit 2 Supporting Data for OD MP2-002-06, dated 1/10/2006
From P. F. LHeureux to R. W. Wells
Operations Read and Sign, December 2005, related to PPC Bladder Trouble Alarm
Boric Acid Corrosion Evaluation, Component 3SIL*MV8840, 10/24/05
Closure Notes for A/R 05007284-02, Richard Perry, 03/01/06
Root Cause Evaluation Report, CR-05-03735, Charging System Alternate Minimum Flow
System Loss of Valve Packing Integrity, 05/25/05
Task Qualification Record, Boric Acid Corrosion Evaluator, Rev 0
Task Qualification Record, Boric Acid Corrosion Inspector, Rev 0
Unit 3 Service Water Brazed Joint Table with Instrumentation Database, Compiled 02/17/06
Fourth Quarter 2005 CR Review For Trends, dated 1/13/06
Unit 2 - Emergency Diesel Generators
System 3326, Service Water, 3rd Quarter 2005
MP2-016-97 MP2-002-06 MP2-080-01 MP2-023-02 MP2-045-03 MP2-012-05
MP2-058-97 MP2-031-00 MP2-090-01 MP2-028-02 MP2-047-03 MP2-001-06
MP2-042-99 MP2-036-00 MP2-012-02 MP2-033-02 MP2-049-03 MP2-001-06
MP2-051-99 MP2-038-00 MP2-014-02 MP2-037-03 MP2-063-04 MP2-002-06
MP2-001-00 MP2-064-01 MP2-020-02 MP2-038-03 MP2-074-04 MP2-030-00
MP2-007-00 MP2-070-01 MP2-021-02 MP2-040-03 MP2-003-05
MP2-025-00 MP2-071-01 MP2-022-02 MP2-043-03
Enclosure
A-8
Vendor Information
VTM 25212-063-001, Installation, Operation, and Maintenance of Service Water Dual
Backwash Strainers, Rev 1
LIST OF ACRONYMS
ACE Apparent Cause Evaluation
AOP Abnormal Operating Procedure
ARP Alarm Response Procedure
BACCP Boric Acid Corrosion Control Program
CAP Corrective Action Program
CDS Chilled Water System
CR Condition Report
DCN Design Change Notice
ECP Employee Concerns Program
ID Inner Diameter
IMC Inspection Manual Chapter
LOCA Loss of Coolant Accident
M&TE Maintenance and Test Equipment
NCV Non-Cited Violation
NRC Nuclear Regulatory Commission
OE Operating Experience
OD Outer Diameter
PARS Publicly Available Records
PI&R Problem Identification and Resolution
RCE Root Cause Evaluation
RECO Reasonable Expectation of Continued Operations
ROP Reactor Oversight Process
SDP Significance Determination Process
SPAR Standardized Plant Analysis Risk
SRA Senior Reactor Analyst
SPAR Standardized Plant Analysis Risk
SSC System/Structure/Component
TDAFW Turbine Driven Auxiliary Feedwater Pump
TSAS Technical Specification Action Statement
Enclosure