ML061070659

IR 05000336-06-006, IR 05000423-06-006; 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 Pro

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

05000423/2006006

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

License Nos.: DPR-65, NPF-49

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

License No.: DPR-65, NPF-49

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

ML061070498.

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

Operability Determinations

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

AFW Auxiliary Feedwater

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

LLRT Local Leak Rate Testing

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

RCS Reactor Coolant System

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