ML080450234

IR 05000266-07-005, 05000301-07-005 on 10/01/2007 - 12/31/2007 for Point Beach, Units 1 & 2, Adverse Weather Protection, Operability Evaluations, Followup of Events, Other Activities

ML080450234
Person / Time
Site:	Point Beach
Issue date:	02/13/2008
From:	Michael Kunowski NRC/RGN-III/DRP/B5
To:	Mccarthy J Florida Power & Light Energy Point Beach
References
FOIA/PA-2010-0209 IR-07-005
Download: ML080450234 (69)

See also: IR 05000266/2007005

Text

February 13, 2008

Mr. James McCarthy

Site Vice President

FPL Energy Point Beach, LLC

6610 Nuclear Road

Two Rivers, WI 54241

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2, NRC INTEGRATED

INSPECTION REPORT 05000266/2007005 AND 05000301/2007005

Dear Mr. McCarthy:

On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC)

completed an integrated inspection at your Point Beach Nuclear Plant, Units 1 and 2.

The enclosed inspection report documents the inspection results, which were discussed

on January 10, 2008, with you and members of your staff.

The inspection examined activities conducted under your license as they relate to safety and

compliance with the Commissions rules and regulations, and with the conditions of your

license. The inspectors reviewed selected procedures and records, observed activities, and

interviewed your personnel.

Based on the results of this inspection, seven NRC-identified and self-revealed findings of very

low safety significance (Green) were identified. Five of these findings were determined to

involve violations of NRC requirements. However, because of the very low safety significance

and because they are entered into your corrective action program, the NRC is treating these

findings as Non-Cited Violations (NCVs), consistent with Section VI.A.1 of the NRC

Enforcement Policy. If you contest any NCV in this report, you should provide a response

within 30 days of the date of this inspection report, with the basis for your denial, to the

U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC

20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory

Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the

Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC

20555-0001; and the Resident Inspector Office at the Point Beach Nuclear Plant.

J. McCarthy

-2-

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its

enclosure, and your response (if any) will be available electronically for public inspection in

the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's document system (ADAMS), accessible from the NRC Web site at

http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Michael A. Kunowski, Chief

Branch 5

Division of Reactor Projects

Docket Nos. 50-266; 50-301

License Nos. DPR-24; DPR-27

Enclosure:

Inspection Report 05000266/2007005; 05000301/2007005

w/Attachment: Supplemental Information

cc w/encl:

M. Nazar, Senior Vice President and Nuclear

Chief Operating Officer

J. Stall, Senior Vice President and

Chief Nuclear Officer

R. Kundalkar, Vice President, Nuclear Technical Services

Licensing Manager, Point Beach Nuclear Plant

M. Ross, Managing Attorney

A. Fernandez, Senior Attorney

K. Duveneck, Town Chairman

Town of Two Creeks

Chairperson

Public Service Commission of Wisconsin

J. Kitsembel, Electric Division

Public Service Commission of Wisconsin

State Liaison Officer

J. McCarthy

-2-

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its

enclosure, and your response (if any) will be available electronically for public inspection in

the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's document system (ADAMS), accessible from the NRC Web site at

http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

Michael A. Kunowski, Chief

Branch 5

Division of Reactor Projects

Docket Nos. 50-266; 50-301

License Nos. DPR-24; DPR-27

Enclosure:

Inspection Report 05000266/2007005; 05000301/2007005

w/Attachment: Supplemental Information

cc w/encl:

M. Nazar, Senior Vice President and Nuclear

Chief Operating Officer

J. Stall, Senior Vice President and

Chief Nuclear Officer

R. Kundalkar, Vice President, Nuclear Technical Services

Licensing Manager, Point Beach Nuclear Plant

M. Ross, Managing Attorney

A. Fernandez, Senior Attorney

K. Duveneck, Town Chairman

Town of Two Creeks

Chairperson

Public Service Commission of Wisconsin

J. Kitsembel, Electric Division

Public Service Commission of Wisconsin

State Liaison Officer

DOCUMENT NAME: G:\\POIN\\Poin 2007 005.doc

Publicly Available

Non-Publicly Available

Sensitive

Non-Sensitive

To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy

OFFICE

RIII

RIII

NAME

RKrsek*MAK for

MKunowski

DATE

2/13/08

2/13/08

OFFICIAL RECORD COPY

Letter to J. McCarthy from M. Kunowski dated February 13, 2008.

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2, NRC INTEGRATED

INSPECTION REPORT 05000266/2007005 AND 05000301/2007005

DISTRIBUTION:

TEB

CFL

EMH1

LXR1

RidsNrrDirsIrib

MAS

KGO

JKH3

CAA1

RGK

LSL (electronic IRs only)

C. Pederson, DRP (hard copy - IRs only)

DRPIII

DRSIII

PLB1

TXN

ROPreports@nrc.gov (inspection reports, final SDP letters, any letter with an IR number)

Enclosure

U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket Nos:

50-266; 50-301

License Nos:

DPR-24; DPR-27

Report No:

05000266/2007005; 05000301/2007005

Licensee:

FPL Energy Point Beach, LLC

Facility:

Point Beach Nuclear Plant, Units 1 and 2

Location:

Two Rivers, Wisconsin

Dates:

October 1, 2007, through December 31, 2007

Inspectors:

R. Krsek, Senior Resident Inspector

R. Ruiz, Resident Inspector

S. Burton, Senior Resident Inspector, Kewaunee

P. Higgins, Resident Inspector, Kewaunee

W. Slawinski, Senior Health Physicist

C. Zoia, Operations Engineer

N. Valos, Senior Operations Engineer

K. Walton, Operations Engineer

R. Winter, Reactor Engineer

M. Jones, Reactor Engineer

Approved by:

Michael Kunowski, Chief

Branch 5

Division of Reactor Projects

2

Enclosure

SUMMARY OF FINDINGS

IR 05000266/2007005, 05000301/20070005; 10/01/2007-12/31/2007; Point Beach Nuclear

Plant, Units 1 & 2; Adverse Weather Protection; Operability Evaluations; Followup of Events;

Other Activities.

This report covers a three-month period of inspections by resident inspectors and regional

specialists. Seven Green findings were identified. Five of the findings which were identified

had associated Non-Cited Violations (NCVs). The significance of most findings is indicated

by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,

Significance Determination Process, (SDP). Findings for which the SDP does not apply

may be Green or be assigned a severity level after NRC management review. The NRCs

program for overseeing the safe operation of commercial nuclear power reactors is described

in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

A.

NRC-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

Green. The inspectors identified a finding of very low safety significance with no

associated violation of regulatory requirements for the licensees failure to control

loose materials in the protected area. Specifically, the inspectors identified

materials that were classified as tornado hazards per station procedure PC 99

near the Unit 1 and Unit 2 main and auxiliary transformers and the switchyard

boundary. Once notified, the licensee entered the issue into its corrective action

program and removed the materials. In addition, a procedure change request

was initiated to incorporate tornado hazard walkdowns into the abnormal

operating procedure for severe weather response.

The finding is more than minor because if left uncorrected, the loose items would

become a more significant safety concern. The finding is of very low safety

significance (Green) because it did not contribute to both the likelihood of a

reactor trip and the likelihood that mitigation equipment or functions will not be

available. Additionally, the inspectors determined that the finding had a cross-

cutting aspect in the area of problem identification and resolution in that the

licensee failed to take appropriate corrective actions to address safety issues and

adverse trends in a timely manner, commensurate with their safety significance

and complexity (P.1(d)). (Section 1R01.1)

Cornerstone: Mitigating Systems

Green. A self-revealed finding with no associated violation of regulatory

requirements was identified for an inadequate operability evaluation performed

in June 2007 for service water pump P-32C. Specifically, the pump failed its

inservice test (IST) on high vibrations after approximately six hours of operation,

but the operability evaluation had concluded the pump vibrations would not reach

the out-of-service limit until after 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> of continuous operation. Contributing

to the unanticipated early failure was the use of non-conservative decision-

making and the use of a non-conservative assumption in the pumps vibration

prediction model. The licensee entered this issue into its corrective action

program and P-32C was subsequently repaired and returned to service.

3

Enclosure

The finding is more than minor because it could reasonably be viewed as a

precursor to a significant event. The finding is of very low safety significance

(Green) because there was no design deficiency, no actual loss of safety

function, no single train loss of safety function for greater than the Technical

Specification (TS) allowed outage time, and no risk due to external events.

Additionally, the inspectors determined that the finding had a cross-cutting aspect

in the area of human performance. Specifically, the licensee failed to use

conservative assumptions in decision-making affecting operability of safety-

related equipment (H.1(b)). (Section 1R15.1)

Green. The inspectors identified a finding of very low safety significance (Green)

and an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, for the failure to adequately assess

operability of the Unit 2 2P-29 turbine-driven auxiliary feedwater (TDAFW) pump.

The licensee failed to implement procedural requirements regarding the

immediate assessment of operability on September 24 and September 27, 2007,

for the increased water ingress into the turbine outboard bearing housing for the

pump following maintenance activities. The licensee took corrective actions,

which included performing an operability evaluation on November 1 when the

next scheduled test again revealed higher than normal levels of water in the

bearing oil. However, the inspectors continued to identify, in the subsequent

revisions to the operability determination, that the licensee failed to utilize all the

data available to assess pump operability. At the end of the inspection period,

the licensee continued to evaluate the causes and corrective actions to address

this finding.

The finding is more than minor because, if left uncorrected, the failure to properly

assess operability would result in the TDAFW pump being degraded, and

possibly inoperable for more than the allowed outage time in accordance with

TSs with no action being taken. The finding is of very low safety significance

(Green) because the inadequate operability determination did not result in

exceeding the allowed outage time of TSs before action was taken. Additionally,

the inspectors determined that the finding had a cross-cutting aspect in the area

of human performance. Specifically, the licensee failed to use conservative

assumptions in decision-making affecting operability of safety-related equipment

(H.1(b)). (Section 1R15.2)

Green. A self-revealed finding and an associated Non-Cited Violation of

10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,

were identified for the failure to have adequate procedures to allow operators to

properly set the thermostat of the Unit 2 refueling water storage tank (RWST)

heaters and to ensure the RWST was recirculated frequently enough for the

temperature indicator to accurately measure bulk temperature. On

September 18, 2007, the Unit 2 RWST was found to be at 105 °F. This

temperature exceeded the TS-maximum allowable limit of 100 °F (97 °F

parametric) and could not be restored to acceptable limits before the eight-hour

TS action statement expired. As a result, a shutdown of Unit 2 was commenced.

At 20 percent power, a return to full power began after the RWST temperature

was restored to within acceptable limits. It was later identified that the undesired

heat-up was caused by the incorrect setting of the controlling thermostat for the

RWST heaters.

4

Enclosure

The finding is more than minor because it is associated with the procedure

quality and human performance attributes of the Mitigating Systems Cornerstone

and affected the cornerstone objective to ensure the availability, reliability, and

capability of systems that respond to initiating events to prevent undesirable

consequences (i.e., core damage). The finding is of very low safety significance

(Green) because the elevated temperature of the RWST and subsequent

shutdown sequence did not contribute to both the likelihood of a reactor trip and

the likelihood that mitigation equipment or functions would not be available.

Additionally, the inspectors determined that the finding had a cross-cutting aspect

in the area of human performance. Specifically, human error prevention

techniques were not utilized prior to and during the thermostat setting task and

personnel proceeded in the face of uncertainty and unexpected circumstances

(H.4(a)). (Section 4OA3.1)

Green. The inspectors identified a finding of very low safety significance and an

associated Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, for the licensees failure to conduct

adequate post-maintenance testing of the Unit 1 1P-29 turbine-driven auxiliary

feedwater (TDAFW) pump following a ten-year overhaul of the turbine in

May 2007. Specifically, the ten-year overhaul maintenance included bearing

replacement, but the TDAFW pump was not run long enough during testing for

bearing temperature to stabilize. The appropriate post-maintenance test would

have detected that the bearing temperatures were rising and required evaluation

prior to declaring the TDAFW pump operable. The licensee entered the issue

into its corrective action program and took immediate corrective actions.

Additionally, the licensee initiated changes to the inadequate procedures.

The finding is more than minor because, if left uncorrected, the issue would have

become a more significant safety concern. The inspectors determined this

finding was not a design qualification deficiency resulting in a loss of function per

NRC Generic Letter 91-18, did not represent an actual loss of safety function of a

system or train of equipment, and was not potentially risk-significant due to a

seismic, fire, flooding, or severe weather initiating event. Therefore, the finding is

considered to be of very low safety significance (Green). Additionally, the

inspectors determined that the finding had a cross-cutting aspect in the area of

human performance. Specifically, the licensee failed to ensure that procedures

were adequate and accurate to assure nuclear safety (H.2(c)). (Section 4OA5.1)

Green. The inspectors identified a finding of very low safety significance and an

associated Non-Cited Violation of 10 CFR 50, Appendix B, Criterion XVI,

Corrective Action, for the failure to implement prompt corrective actions for the

degraded oil conditions initially identified with the Unit 2 2P-29 turbine-driven

auxiliary feedwater (TDAFW) pump on September 24, 2007, following

maintenance. Following an additional oil sample with favorable results, the

licensee incorrectly concluded, due to confirmational biases, that the high water

content of the first oil sample was an expected condition. The licensee wrote a

condition report, but it was closed with no actions taken. In November 2007, the

licensee identified that a significant degraded oil condition existed with the pump.

The licensee entered the issue into its corrective action program and took

immediate corrective actions, including rebuilding the pump turbine. The

5

Enclosure

licensee continued to evaluate the causes and corrective actions to address this

finding at the end of the inspection period.

The finding is more than minor because it could reasonably be viewed as a

precursor to a significant event. Specifically, the failure to correct the cause of

the oil degradation in a timely manner in September 2007 could have resulted in

the failure of the 2P-29 TDAFW pump. The finding is of very low safety

significance (Green) because there was no design deficiency, no actual loss of

safety function, no single train loss of safety function for greater than the TS

allowed outage time, and no risk due to external events. Additionally, the

inspectors determined that the finding had a cross-cutting area aspect in the

area of problem identification and resolution. Specifically, the licensee failed to

thoroughly evaluate the problem with water ingress into the oil, such that a

resolution addressed the cause and extent of condition (P.1(c)).

(Section 4OA5.2.b.1)

Cornerstone: Other

Green. The inspectors identified a finding of very low safety significance and

an associated Non-Cited Violation of 10 CFR 72.48(c)(1) for the licensees

failure to obtain a Certificate of Compliance (CoC) amendment pursuant to

10 CFR 72.244, for changes made in the spent fuel storage cask operating

procedures during the 2004 loading campaign as described in the Final Safety

Analysis Report. The procedure changes constituted a change in the terms,

conditions, or specifications incorporated in the CoC. Although the procedures

were contained in the Final Safety Analysis Report, the licensee failed to identify

that TS 1.2.17a, 32PT Dry Storage Canister (DSC) Vacuum Drying Duration

Limit, was also affected by the procedure change and required prior NRC

approval. The licensee implemented corrective actions, which included revising

the loading procedure to reflect the sequence described in the FSAR prior to the

next cask loading campaign.

This finding is more than minor because it had the potential to impact the NRCs

ability to perform its regulatory function, since the licensee failed to receive NRC

approval for a change in this licensed activity. The inspectors determined that

the finding was not suitable for SDP evaluation because the noncompliance

involved 10 CFR Part 72 dry fuel storage activities. Therefore, this finding was

reviewed by regional management and dispositioned using traditional

enforcement. The finding was determined to be of very low safety significance

(Green). (Section 4OA5.5)

B.

Licensee-Identified Violations

No violations of significance were identified.

6

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 was at 100 percent power throughout the inspection period with the exception of brief

reductions in power during routine auxiliary feedwater pump and secondary system valve

testing.

Unit 2 was at 100 percent power throughout the inspection period with the exception of brief

reductions in power during routine auxiliary feedwater pump and secondary system valve

testing.

1.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

.1

Readiness For Impending Adverse Weather Condition - High Wind Conditions

a.

Inspection Scope

Because high winds were forecast in the vicinity of the facility for October 18, 2007, the

inspectors reviewed the licensees overall preparations for the expected weather

conditions. The inspectors walked down important outdoors areas within the protected

area, in addition to the licensees emergency alternating current (AC) power systems,

because safety-related functions could be affected by, or required as a result of, high

winds or tornado-generated missiles. The inspectors focused on the licensees

procedures used to respond to specified adverse weather conditions and toured the

plant grounds for loose debris, which could become missiles during a tornado or high

winds condition. The inspectors evaluated the licensees preparations against the sites

procedures and evaluated the adequacy of the staffs response. The inspectors also

verified that the licensee was identifying adverse weather issues at an appropriate

threshold and entering them into its corrective action program in accordance with station

procedures.

This inspection constituted one sample prior to the onset of an adverse weather.

b.

Findings

Introduction: The inspectors identified a finding of very low safety significance (Green)

for the licensees failure to control loose materials in the protected area. Specifically, the

inspectors identified materials that were classified as tornado hazards per licensee

procedure PC 99 and were near the Unit 1 and Unit 2 main and auxiliary transformers

and the switchyard boundary. No violation of regulatory requirements occurred.

Description: On October 18, 2007, the inspectors conducted a walkdown of the risk

significant portions of the main and auxiliary power system to assess the licensees

preparations to preclude or minimize potential damage from high winds associated with

severe storms or tornadoes. During the walkdown, the inspectors identified a significant

quantity of unsecured materials meeting the definition of tornado hazards provided in

7

Enclosure

Point Beach procedure PC 99, Tornado Hazards Inspection Checklist, near the subject

transformers. The inspectors concluded that high winds or tornadoes combined with the

proximity of the transformers to the large quantity of unsecured materials increased the

potential to damage the transformers or related electrical equipment. The inspectors

informed the licensee of the concern and the licensee took immediate corrective action

to clean the areas identified by the inspectors and entered the issue into the corrective

action program as corrective action program document (CAP, condition report)

CAP 01114731. The licensee also commenced a walkdown of outside areas within the

protected area to address extent of condition. In addition, the licensee initiated a

procedure change request to incorporate tornado hazard walkdowns into Abnormal

Operating Procedure (AOP) 13C, Severe Weather Conditions.

Analysis: The inspectors determined that the failure of licensee personnel to control

material in the protected area near risk significant equipment is a performance

deficiency. Using the guidance contained in Inspection Manual Chapter (IMC) 0612,

Power Reactor Inspection Reports. Appendix B, Issue Disposition Screening, dated

September 20, 2007, the inspectors determined that the finding is more than minor

because, if left uncorrected, the loose items in the vicinity of the main and auxiliary

transformers, and near the switchyard, would become a more significant safety concern.

The inspectors determined that the finding warranted evaluation using the Significance

Determination Process (SDP) because the finding is associated with an increase in the

likelihood of an initiating event.

The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1,

Significance Determination of Reactor Inspection Findings for At-Power Situations,

dated January 10, 2008. Using the Phase 1 SDP worksheet for the Initiating Event

Cornerstone, transient initiator contributor, the inspectors determined that the finding did

not contribute to the likelihood of a primary or secondary system loss of coolant accident

initiator; the finding did not contribute to both the likelihood of a reactor trip and the

likelihood that mitigation equipment or functions will not be available; and the finding did

not increase the likelihood of a fire or internal or external flooding. Therefore, the finding

is determined to be of very low safety significance (Green).

The inspectors performed a review of past corrective action program documents to

assess the effectiveness of the licensees corrective actions to address similar issues.

During this review, inspectors noted that an NRC-identified finding, 05000266/000301-

2006004-01, was issued in July 2006 for a nearly identical issue related to the failure to

control loose material in the protected area. Procedure PC 99 was created as a

corrective action for that finding. In addition, inspectors noted that between May and

September 2007, there have been a number of CAPs written as a result of the

identification of tornado hazards in the protected area during the use of procedure

PC 99. Consequently, the inspectors determined that the finding had a cross-cutting

aspect in the area of problem identification and resolution. Specifically, the licensee

failed to take appropriate corrective actions to address safety issues and adverse trends

in a timely manner, commensurate with their safety significance and complexity (P.1(d)).

Enforcement: The failure to maintain the protected area free of tornado hazards was not

an activity affecting quality subject to 10 CFR Part 50, Appendix B, nor was a procedure

required by license conditions or TSs violated. Therefore, while a performance

deficiency existed, no violation of regulatory requirements occurred. This is considered

a finding of very low safety significance (FIN 05000266/2007005-01;

8

Enclosure 05000301/2007005-01). The licensee included this finding in its corrective action

program as CAP 01114731.

.2

Winter Seasonal Readiness Preparations

a.

Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to

verify that the plants design features and implementation of procedures were sufficient

to protect mitigating systems from the effects of adverse weather. Documentation for

selected risk-significant systems was reviewed to ensure that these systems would

remain functional when challenged by inclement weather. During the inspection, the

inspectors focused on plant specific design features and the licensees procedures used

to prepare for the onset of cold weather. Additionally, the inspectors reviewed licensee

corrective actions for areas in the plant which previously had cold weather issues. Cold

weather protection equipment, such as the façade freeze heat tracing and temporary

area heaters, were verified to be in operation when applicable. The inspectors also

reviewed corrective action program items to verify that the licensee was identifying cold

weather issues at an appropriate threshold and entering them into the corrective action

program in accordance with procedures. The inspectors reviews focused specifically on

the following plant systems due to their risk significance or susceptibility to cold weather

issues: main steam system and instrumentation, including the atmospheric steam

dumps and the main steam isolation valve; emergency core cooling system, including

the refueling water storage tank and associated piping; and the façade freeze system.

This inspection constituted one winter seasonal system readiness sample.

b.

Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

.1

Quarterly Partial System Walkdowns

a.

Inspection Scope

The inspectors performed partial walkdowns of accessible portions of risk-significant

systems to determine the operability of these systems. The inspectors utilized system

valve lineup and electrical breaker checklists, tank level books, plant drawings, and

selected operating procedures to determine whether the systems were correctly aligned

to perform the intended design functions. The inspectors also examined the material

condition of the components and observed operating equipment parameters to

determine whether deficiencies existed. The inspectors reviewed completed work

orders (WOs) and calibration records associated with the systems for issues that could

affect component or train functions. The inspectors used the information in the

appropriate sections of the Final Safety Analysis Report (FSAR) to determine the

functional requirements of the system.

Partial system walkdowns of the following systems constituted two inspection procedure

samples:

9

Enclosure

Emergency diesel generator (EDG) G01 aligned to busses 1A05 and 2A05 while

EDG G02 was out-of-service the week of October 22, 2007; and

EDG G02 aligned to busses 1A05 and 2A05 while EDG G01 was out-of-service

the week of November 19, 2007.

b.

Findings

No findings of significance were identified.

.2

Semi-Annual Complete System Walkdown

a.

Inspection Scope

In November 2007, the inspectors performed a complete system alignment inspection of

the auxiliary feedwater (AFW) system for Units 1 and 2 to verify the functional capability

of the system. This system was selected because it was considered both safety-

significant and risk-significant in the licensees probabilistic risk assessment. The

inspectors walked down the system to review mechanical and electrical equipment line-

ups, electrical power availability, system pressure and temperature indications,

component labeling, component lubrication, component and equipment cooling, hangers

and supports, operability of support systems, and to ensure that ancillary equipment or

debris did not interfere with equipment operation. A review of past and outstanding WOs

was performed to determine whether any deficiencies significantly affected system

function. In addition, the inspectors reviewed the CAP database to ensure that system

equipment alignment problems were being identified and appropriately resolved. The

documents used for the walkdown and issue review are listed in the attached List of

Documents Reviewed.

These activities constituted one complete system walkdown inspection procedure

sample.

b.

Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

.1

Routine Resident Inspector Tours (71111.05Q)

a.

Inspection Scope

The inspectors conducted fire protection walkdowns, which focused on the following

attributes: the availability, accessibility, and condition of fire fighting equipment; the

control of transient combustibles and ignition sources; and the condition and status of

installed fire barriers. The inspectors selected fire areas for inspection based on the

areas overall fire risk contribution, as documented in the Individual Plant Examination of

External Events, or the potential of a fire to impact equipment that could initiate a plant

transient.

In addition, the inspectors assessed these additional fire protection attributes during

walkdowns: fire hoses and extinguishers were in the designated locations and available

10

Enclosure

for immediate use; unobstructed fire detectors and sprinklers; transient material loading

within the analyzed limits; and fire doors, dampers, and penetration seals in satisfactory

condition. The inspectors also determined whether minor issues identified during the

inspection were entered into the licensees corrective action program.

The walkdown of the following selected fire zones constituted three inspection procedure

samples:

Unit 2 TDAF Room

EDG G01 Room

EDG G02 Room

b.

Findings

No findings of significance were identified.

.2

Annual Fire Protection Drill Observation (71111.05A)

a.

Inspection Scope

During this quarter, the inspectors observed two fire brigade activation drills: an

October 9, 2007, drill scenario that simulated a fire in the Unit 2 2P-2C charging pump

room and a November 26 drill scenario that simulated a fire in the unit common cable

spreading room. The combined drill observations were used to determine the readiness

of the plant fire brigade to fight fires. The inspectors verified that the licensee staff

identified deficiencies, openly discussed them in a self-critical manner at the drill

debriefs, and took appropriate corrective actions. Specific attributes evaluated were:

(1) proper wearing of turnout gear and self-contained breathing apparatus; (2) proper

use and layout of fire hoses; (3) employment of appropriate fire fighting techniques;

(4) sufficient firefighting equipment brought to the scene; (5) effectiveness of fire brigade

leader communications, command, and control; (6) search for victims and propagation of

the fire into other plant areas; (7) smoke removal operations; (8) utilization of pre-

planned strategies; (9) adherence to the pre-planned drill scenario; and (10) drill

objectives.

These activities constituted one annual fire protection inspection sample.

b.

Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a.

Inspection Scope

The inspectors reviewed the licensees testing of the EDG G01 and G02 heat

exchangers one month following their replacement to verify that potential deficiencies

did not affect the licensees ability to detect degraded performance, and to identify any

common cause issues that had the potential to increase risk, and to ensure that the

licensee was adequately addressing problems that could result in initiating events that

would cause an increase in risk. The inspectors also verified that the new heat

11

Enclosure

exchangers were less susceptible to lake grass fouling, than the original heat

exchangers. The inspectors reviewed the licensees observations as compared against

acceptance criteria, the correlation of scheduled testing and the frequency of testing,

and the impact of instrument inaccuracies on test results. Inspectors also verified that

test acceptance criteria considered differences between test conditions, design

conditions, and testing criteria.

This inspection constituted one inspection procedure sample.

b.

Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

.1

Resident Inspector Quarterly Review

a.

Inspection Scope

In November 2007, the inspectors observed a crew of licensed operators in the plants

simulator during licensed operator training to verify that operator performance was

adequate, evaluators were identifying and documenting crew performance problems,

and training was being conducted in accordance with licensee procedures. The

inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures;

control board manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and Emergency Plan

actions and notifications.

The crews performance in these areas was compared to pre-established operator action

expectations and successful critical task completion requirements.

This inspection constituted one quarterly licensed operator requalification program

sample.

b.

Findings

No findings of significance were identified.

.2

Facility Operating History

a.

Inspection Scope

The inspectors reviewed the plants operating history from September 2005 through

October 2007 to identify operating experience that was expected to be addressed by the

12

Enclosure

Licensed Operator Requalification Training (LORT) program. It was then verified that

the identified operating experience had been addressed by the facility licensee in

accordance with the stations approved Systems Approach to Training (SAT) program to

satisfy the requirements of 10 CFR 55.59(c), Requalification program requirements.

b. Findings

No findings of significance were identified.

.3

Licensee Requalification Examinations

a.

Inspection Scope

The inspectors performed a biennial inspection of the licensees LORT test/examination

program for compliance with the stations SAT program that would satisfy the

requirements of 10 CFR 55.59(c)(4), Evaluation. The inspectors reviewed the 2006

biennial written requalification examinations and 2007 annual operating test material to

evaluate general quality, construction, and difficulty level. The written examinations

reviewed consisted of four written examinations, each containing 30 questions. The

operating examination material consisted of 6 operating tests, each containing

approximately two dynamic simulator scenarios and five job performance measures

(JPMs). The inspectors reviewed the annual requalification operating test and biennial

written examination material to evaluate general quality, construction, and difficulty level.

The inspectors assessed the level of examination material duplication from week-to-

week during the current year operating test and written examinations. The inspectors

reviewed the methodology for developing the examinations, including the LORT program

two-year sample plan, probabilistic risk assessment insights, previously identified

operator performance deficiencies, and plant modifications.

b.

Findings

No findings of significance were identified.

.4

Licensee Administration of Requalification Examinations

a.

Inspection Scope

The inspectors observed the administration of a requalification operating test to assess

the licensees effectiveness in conducting the test to ensure compliance with

10 CFR 55.59(c)(4), Evaluation. The inspectors evaluated the performance of one

crew in parallel with the facility evaluators during one dynamic simulator scenario and

evaluated various licensed crew members concurrently with facility evaluators during the

administration of several JPMs. The inspectors assessed the facility evaluators ability

to determine adequate crew and individual performance using objective, measurable

standards. The inspectors observed the training staff personnel administer the operating

test, including conducting pre-examination briefings, evaluations of operator

performance, and individual and crew evaluations upon completion of the operating test.

The inspectors evaluated the ability of the simulator to support the examinations. A

specific evaluation of simulator performance was conducted and documented under

Section 1R11.9 of this report.

13

Enclosure

b.

Findings

No findings of significance were identified.

.5

Examination Security

a.

Inspection Scope

The inspectors observed and reviewed the licensees overall licensed operator

requalification examination security program related to examination physical security

(e.g., access restrictions and simulator considerations) and integrity (e.g., predictability

and bias) to verify compliance with 10 CFR 55.49, Integrity of examinations and tests.

The inspectors also reviewed the facility licensees examination security procedure, any

corrective actions related to past or present examination security problems at the facility,

and the implementation of security and integrity measures (e.g., security agreements,

sampling criteria, bank use, and test item repetition) throughout the examination

process.

b.

Findings

There was one issue associated with examination security identified by the licensee

during the administration of JPMs during the sixth week of administration of the 2007

annual operating test. On October 31, 2007, an individual who had just completed a

simulator JPM was escorted back to the waiting room area and dropped off. However,

there was no examination sequesterer in the waiting room area to ensure that there was

no examination compromise with individuals in the room who had not been administered

the JPM. Within two minutes, the licensee identified the potential for an examination

compromise. The licensee determined that the individual who had just been

administered the JPM did not communicate any exam-related information to any other

individuals who had not been administered the JPM. As part of its corrective actions, the

licensee held a training department standdown with the members of the examination

team. The licensee replaced the JPM in question for the remaining individuals to be

tested. The issue was documented in the corrective action program as CAP 01115710.

The NRC was appropriately notified of the issue. The issue was reviewed and assessed

for a possible violation of 10 CFR 55.49, Integrity of examinations and tests. With the

actions taken, it was determined that no actual examination compromise had occurred.

The issue was not subject to enforcement action in accordance with NRC enforcement

policy.

.6

Licensee Training Feedback System

a.

Inspection Scope

The inspectors assessed the methods and effectiveness of the licensees processes

for revising and maintaining its LORT program up-to-date, including the use of feedback

from plant events and industry experience information. The inspectors reviewed the

licensees quality assurance oversight activities, including licensee training department

self-assessment reports. The inspectors evaluated the licensees ability to assess the

effectiveness of its LORT program and its ability to implement appropriate corrective

14

Enclosure

actions. This evaluation was performed to verify compliance with 10 CFR 55.59(c)

Requalification program requirements, and the licensees SAT program.

b.

Findings

No findings of significance were identified.

.7

Licensee Remedial Training Program

a.

Inspection Scope

The inspectors assessed the adequacy and effectiveness of the remedial training

conducted since the previous biennial requalification examinations and the training from

the current examination cycle to ensure that they addressed weaknesses in licensed

operator or crew performance identified during training and plant operations. The

inspectors reviewed remedial training procedures and individual remedial training plans.

This evaluation was performed in accordance with 10 CFR 55.59(c), Requalification

program requirements, and with respect to the licensees SAT program.

b.

Findings

No findings of significance were identified.

.8

Conformance with Operator License Conditions

a. Inspection Scope

The inspectors reviewed the facility and individual operator licensees' conformance

with the requirements of 10 CFR Part 55. The inspectors reviewed the facility licensee's

program for maintaining active operator licenses and to assess compliance with

10 CFR 55.53(e) and (f). The inspectors reviewed the procedural guidance and the

process for tracking on-shift hours for licensed operators and which control room

positions were granted watch-standing credit for maintaining active operator licenses.

The inspectors reviewed the facility licensee's LORT program to assess compliance with

the requalification program requirements as described by 10 CFR 55.59(c). Additionally,

medical records for seven licensed operators were reviewed for compliance with

10 CFR 55.53(i).

b. Findings

No findings of significance were identified.

.9

Conformance with Simulator Requirements

a.

Inspection Scope

The inspectors assessed the adequacy of the licensees simulation facility (simulator) for

use in operator licensing examinations and for satisfying experience requirements as

prescribed in 10 CFR 55.46, Simulation facilities. The inspectors also reviewed a

sample of simulator performance test records (i.e., transient tests, malfunction tests, and

core performance tests), simulator discrepancies, and the process for ensuring

15

Enclosure

continued assurance of simulator fidelity in accordance with 10 CFR 55.46. The

inspectors reviewed and evaluated the discrepancy process to ensure that simulator

fidelity was maintained. Open simulator discrepancies were reviewed for importance

relative to the impact on 10 CFR 55.45 and 55.59 operator actions, as well as on nuclear

and thermal hydraulic operating characteristics. The inspectors interviewed the

licensees simulator staff about the configuration control process and completed the

Inspection Procedure 71111.11, Appendix C checklist, to evaluate whether the

licensees plant-referenced simulator was operating adequately as required by

10 CFR 55.46(c) and (d).

b.

Findings

No findings of significance were identified.

.10

Annual Operating Test Results

a.

Inspection Scope

The inspectors reviewed the overall pass/fail results of the annual JPM operating tests,

and the annual simulator operating tests (required to be given per 10 CFR 55.59(a)(2))

administered by the licensee during 2007. The overall results were compared with the

SDP in accordance with IMC 0609, Appendix I, Operator Requalification Human

Performance Significance Determination Process (SDP), dated August 22, 2005. The

year 2007 was the first year of the licensees 24-month training program; therefore, no

written examination was administered in 2007.

This represented one sample.

b.

Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

a.

Inspection Scope

The inspectors reviewed risk assessments for planned and emergent maintenance

activities during the specified work weeks. During these reviews, the inspectors

compared the licensees risk management actions to those actions specified in the

licensees procedures for the assessment and management of risk associated with

maintenance activities. The inspectors assessed whether evaluation, planning, control,

and performance of the work were done in a manner to reduce the risk and minimize the

duration, where practical, and whether contingency plans were in place where

appropriate.

The inspectors used the licensees daily configuration risk assessment records,

observations of shift turnover meetings and observations of daily plant status meetings

to determine whether the equipment configurations were properly listed. The inspectors

also verified that protected equipment was identified and controlled as appropriate and

that significant aspects of plant risk were communicated to the necessary personnel.

16

Enclosure

The reviews of maintenance risk assessment and emergent work evaluation constituted

five inspection procedure samples:

Planned and emergent maintenance during the week of October 15, 2007;

Planned and emergent maintenance during the week of October 22;

Planned and emergent maintenance during the week of October 29;

Planned and emergent maintenance during the week of November 26; and

Planned and emergent maintenance during the week of December 10.

b.

Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

.1

Service Water (SW) Pump P-32C Issues

a.

Inspection Scope

The inspectors reviewed CAP 01098680, its associated operability evaluation (OPR),

apparent cause evaluation (ACE), and past operability evaluation in the licensees

corrective action program. The inspectors reviewed design basis information, the FSAR,

TS requirements, and licensee procedures to determine the technical adequacy of the

operability evaluations. The inspectors also reviewed the licensees implementation of

select sections of the American Society of Mechanical Engineers (ASME) Operational

Maintenance (OM) Code, 1995 Addenda, to evaluate whether requirements were met

and the appropriate actions were taken in accordance with the Code. In addition, the

inspectors determined whether compensatory measures were implemented, as required.

The inspectors assessed whether system operability was properly justified and that the

system remained available, such that no unrecognized increase in risk occurred.

This review constituted one sample.

b.

Findings

Introduction: A self-revealing finding with no associated violation of regulatory

requirements was identified for an inadequate operability evaluation issued on

June 28, 2007, associated with safety-related SW pump P-32C. Specifically, P-32C

failed its inservice test (IST) on high vibrations after only 6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of operation, but the

June 2007 operability evaluation had concluded that the pump would remain operable

and not reach the IST out-of-service limit until 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> of continuous operation. The

licensees non-conservative decision-making and use of a non-conservative prediction

model led to the incorrect conclusion of operability of the P-32C pump. Had the licensee

used an appropriate prediction model, reflective of a degraded/degrading pump, the

OPR would have concluded the pump was inoperable.

Description: Service water pump P-32C was placed on increased IST frequency after

trending into the IST Alert Range in May 2007. On June 24, 2007, during the next

performance of increased frequency testing, P-32C vibration was recorded at 0.3051

inches per second (ips) compared to the Required Action limit of > 0.327 ips. Because

this vibration measurements approaching this out-of-service limit of the pump,

17

Enclosure

OPR 01098680 was performed to: review the vibration trend and determine the

additional run time until the IST out-of-service limit might be reached, compare this

duration to the mission time of the P-32C pump, and determine if any additional

compensatory measures were required to be taken.

Licensee engineers utilized vibration analysis software to predict the point at which

P-32C would exceed the 0.327 ips out-of-service limit. Based on the licensees

assumption that the degrading vibration trend was due to normal bearing wear, the trend

projection grossly overestimated the pumps remaining acceptable run time.

Specifically, the model predicted that an additional 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br />, or five days, of continuous

operation could be achieved before reaching 0.327 ips. On August 8, 2007, however,

the next increased frequency IST was performed on P-32C and a vibration level of

0.4055 ips was observed. Because this value exceeded the 0.327 ips IST out-of-service

limit, P-32C was declared inoperable and the appropriate TS action statement was

entered. The pump was subsequently rebuilt and returned to service on August 11 after

71 hours8.217593e-4 days <br />0.0197 hours <br />1.173942e-4 weeks <br />2.70155e-5 months <br /> of unavailability.

The inspectors reviewed ACE 01098680-02. The purpose of this ACE was to determine

the cause of the unexpected step change in vibrations and to determine why vibrations

exceeded the IST out-of-service limit in only 6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> vice the 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> of predicted

run time. From the review, the inspectors concluded that the licensee applied non-

conservative assumptions to the vibration trend projection when it failed to factor in

vibration amplifying resonance effects, or any additional conservative margin for

uncertainty.

The inspectors identified another example of the licensees non-conservative

decision-making. Specifically, the licensees OPR did not conservatively address

the 30-day design basis mission time of the SW pumps when the IST out-of-service

limit was predicted to be reached in less than the full 30-day mission time.

Section ISTB 6.2.2 of the Code states: If the measured test parameter values fall

within the required action range, the pump shall be declared inoperable until either

the cause of the deviation has been determined and the condition is corrected, or an

analysis of the pump is performed and new reference values are established in

accordance with paragraph ISTB 4.6. of the Code. The licensee did not declare

P-32C inoperable when it was identified that the vibration parameters would exceed the

required action limit within the 30-day mission time of the pump, nor were new baseline

values established in accordance with the Code.

Analysis: The inspectors determined that the failure to use appropriate, conservative,

calculation assumptions in the trend projection to justify the basis for the continued

operability of a safety-related-pump, is a performance deficiency and a finding. The

finding is more than minor because it could reasonably be viewed as a precursor to a

significant event.

Using IMC 0609, Significance Determination Process, dated January 10, 2008, the

inspectors determined that the finding is of very low safety significance (Green) because

the finding did not involve a design deficiency, there was no actual loss of safety

function, no single train loss of safety function for greater than the TS-allowed outage

time, and no risk due to external events.

18

Enclosure

Additionally, the inspectors determined that the finding had a cross-cutting aspect in the

area of human performance. Specifically, the licensee failed to use conservative

assumptions in making decisions affecting the operability of safety-related components

(H.1(b)).

Enforcement: The failure to perform an adequate operability evaluation, which was

based upon non-conservative decision-making and a non-conservative trend projection,

was not a violation of regulatory requirements although a performance deficiency

existed. Therefore, this issue is considered a finding of very low safety significance

(FIN 05000266/2007005-02; 05000301/2007005-02).

The licensee included this finding in its corrective action program as CAP 01119241 and

has actions planned to perform an ACE to address the use of IST trend data in OPRs.

.2

Operability Evaluations for the Unit 2 TDAFW Pump 2P-29 Following Overhaul

a.

Inspection Scope

The inspectors reviewed selected immediate operability evaluations and operability

evaluations associated with issues entered into the licensees corrective action program.

The inspectors reviewed design basis information, the FSAR, TS requirements, and

licensee procedures to determine the technical adequacy of the operability evaluations.

In addition, the inspectors determined whether compensatory measures were

implemented, as required. The inspectors assessed whether system operability was

properly justified and that the system remained available, such that no unrecognized

increase in risk occurred.

The reviews of the following OPRs constituted six samples:

CAP 01112660, 2P-29 Outboard Bearing Water Following IT-09A, dated

September 24, 2007;

CAP 01113318, IT-09A Oil Analysis Results Not as Expected for 2P-29, dated

September 27, 2007;

OPR1098358, Moisture Observed in Oil Sample From 2P-29 Outboard Bearing,

Revision 2, dated November 3, 2007;

OPR1098358, Moisture Observed in Oil Sample From 2P-29 Outboard Bearing,

Revision 3, dated November 4, 2007;

OPR1098358, Moisture Observed in Oil Sample From 2P-29 Outboard Bearing,

Revision 4, dated November 7, 2007; and

OPR1098358, Moisture Observed in Oil Sample From 2P-29 Outboard Bearing,

Revision 5, dated November 10, 2007.

b.

Findings

Introduction: The inspectors identified a finding of very low safety significance (Green)

and an associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, for the failure to adequately assess operability

of the Unit 2 TDAFW pump in accordance with plant procedures. The inspectors

identified that the licensee failed to implement procedural requirements regarding the

immediate assessment of operability on September 24 and September 27, 2007, for the

19

Enclosure

increased water ingress into the turbine outboard bearing housing for the pump following

maintenance.

Description: On September 24, 2007, following the overhaul of the 2P-29 TDAFW

pump, an oil sample was taken from the outboard bearing housing, after a four-hour

run. CAP 01112660 was written, which documented that an estimated water volume in

the oil sample based on visual indication was approximately 1,000 to 1,500 parts per

million (ppm) for the four-hour run. The CAP description concluded that this was an

expected condition. A second shorter pump run was performed and the water content in

the oil was visually estimated to be approximately 100 ppm of water. The licensee

rationalized that the initial water content was expected and the condition report was

closed with no further actions taken. However, the inspectors identified that neither the

operations nor engineering staff questioned why a visual estimate for indication of water

in the oil would have produced five times the amount of water in the oil immediately

following the overhaul, as compared to the first oil sample taken in June 2007 following a

November 2006 overhaul, which showed 300 ppm water in the oil. The June 2007

outboard oil sample for the 2P-29 turbine was the first time the oil was sampled since the

November 2006 overhaul and the first time water ingress was noted in the turbine

outboard bearing.

On September 27, CAP 01113318 was written and documented that the outboard oil

sample from the first four-hour run, analyzed by a laboratory, contained 20,040 ppm of

water (approximately two percent by volume). The CAP description also noted that the

number was not consistent with the visual estimate from September 24 of 1,000 to

1,500 ppm. However, the CAP dismissed the results, based on conjecture, concluding

that the 20,040 ppm results were false readings due to a laboratory error or an

accidental capture of water droplets during the sampling process. The CAP concluded

that the indicated levels of water in the IT-09A sample are errant. The immediate

operability assessment concluded that based on the information provided in the

description section there were no operability concerns. In addition, the assessment

discussed that the pump was tested satisfactorily, with no abnormal indications observed

during the run. The inspectors, as well as the licensee personnel performing the causal

evaluation for this issue, concluded that the increased water first observed on

September 24 should not have been discounted and was discounted due to

confirmational biases, resulting in nonconservative assumptions in the evaluation of this

condition.

The inspectors reviewed the licensees procedure for operability, Fleet Procedure

FP OP-OL-01, Operability Determination. The procedure required a determination if

a condition existed that could call into question the ability of a structure, system, or

component (SSC) to perform its specified safety function. An example of such a

condition was an item which met the definition of a degraded condition. A degraded

condition, as defined in the fleet procedure, was a condition where there had been a

noticeable change in parameters that were precursors to failure. The attachment

guidance for immediate operability review also highlighted questions for performing

operability determinations, which included the following: Could the capability of a SSC

to prevent or mitigate consequences of an accident as postulated in the Final Safety

Analysis Report be reduced? The guidance suggested that an OPR should be

requested if additional engineering evaluation and justification was needed to answer

those questions. Finally, the inspectors noted that the guidelines for operability

recommendations included guidance to evaluate trend data to identify a deteriorating

20

Enclosure

condition and to utilize an OPR to predict the point when a SSC may become

inoperable. The inspectors concluded the licensee had not adequately implemented the

procedures for operability determinations for the September 24 and 27 CAPs. The

licensee had not assessed the parameter of a significant increase in the ingress of water

following a maintenance overhaul, as compared to the last maintenance overhaul.

On November 1, 2007, approximately 5 weeks after the maintenance overhaul, the

licensee ran 2P-29 for about two hours and then sampled the oil. The outboard oil

sample had 29,515 ppm of water in the oil. The licensee declared the pump inoperable

and revised the July 2007 operability evaluation for the original water ingress issue in

June.

On November 3, the licensee issued Revision 2 to OPR1098358 and the pump was

determined to be capable of performing the design functions for the design basis mission

time of eight hours. On November 4, Revision 3 to OPR1098358 was issued to specify

a compensatory measure of testing the pump every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for an eight-hour duration.

The subsequent pump runs continued to show high levels of water in the outboard

bearing oil. The inspectors identified that Revisions 2 and 3 utilized data from 2P-29 on

water ingress rates prior to the September 2007 turbine overhaul. These values were

not applicable to the current condition, because the September maintenance had

created a new and greater water ingress problem. Revision 4 to OPR1098358, issued

on November 7, was a rewrite of the OPR utilizing current oil analysis data from after the

overhaul. In addition, the licensee hypothesized, as part of the operability discussion,

that differences in water concentrations in the oil seen since November 1 were likely the

result of a change in sampling techniques. However, the inspectors noted that these

theories were refuted by visual observation and comparison of the quarantined oil

samples taken since November 1. Further testing of the previous oil samples also

refuted the sampling technique theories. In addition, the inspectors noted that the

licensee did not have any established procedural controls or work instructions for mixing

of the samples and splitting of the samples to ensure quality control. The licensee

initiated a condition report and took immediate corrective actions to address this latter

issue. Revision 5 to the OPR was issued on November 10 and contained additional

discussion on the potential for an unexpected increase in steam leakage, and additional

information related to the sampling technique and testing duration.

The inspectors noted that for all the revisions, the OPR demonstrated that the TDAFW

pump would have performed the required safety functions for the eight-hour mission time

of the FSAR Chapter 14 design basis accidents. However, the inspectors pointed out to

the licensee that the OPR did not address all the safety functions required to be

performed by the TDAFW pump, which at Point Beach included several fire-related

scenarios. The licensee subsequently initiated a CAP for this issue.

Additional information regarding the issues associated with the 2P-29 TDAFW pump is

documented in Section 4OA5.2 of this report.

Analysis: The inspectors determined that the failure to adequately perform an operability

determination was a performance deficiency and a finding that warranted a significance

evaluation. Using IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue

Screening, dated September 20, 2007, the inspectors determined that the finding is

more than minor because, if left uncorrected, the failure to properly assess operability

21

Enclosure

would result in the TDAFW pump being degraded and potentially inoperable, exceeding

the allowed outage time in accordance with TSs.

Using IMC 0609, Appendix A, Determining the Significance of Reactor Inspection

Findings for At-Power Situations, dated January 10, 2008, the inspectors determined

the finding may have resulted in a late determination of an actual loss of safety function

of a system or train of equipment. The risk assessment for the potential loss of safety

function is attributed to the performance deficiencies associated with inadequate

maintenance discussed in Section 4OA5.2.b.2 as URI 5000266/2007005-07. This did

not cause the loss of safety function for greater than the allowed outage time.

Therefore, the finding is considered to be of very low safety significance (Green).

Additionally, the inspectors determined that the finding has a cross-cutting aspect in the

area of human performance. Specifically, the licensee failed to use conservative

assumptions in decision-making affecting operability of safety-related equipment

(H.1(b)).

Enforcement: 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures,

and Drawings, requires, in part, that activities affecting quality be prescribed and

accomplished by procedures appropriate to the circumstances. The licensee failed

to implement the operability determination procedure FP-OP-OL-01, Operability

Determination. The procedure required, in part, that the licensee assess the

capability of a SSC to prevent or mitigate consequences of an accident as

postulated in the FSAR. Contrary to this, the licensee failed to adequately assess

the operability of the turbine outboard bearing for the Unit 2 TDAFW pump following

increased water intrusion during post-maintenance testing on September 24, 2007,

and later corroborated by oil analyses on September 27. Because this finding was of

very low safety significance (Green) and because it was entered into the licensees

corrective action program (as CAP 01115748), this violation is being treated as a

Non-Cited Violation, consistent with Section VI.A of the NRC Enforcement Policy

(NCV 05000301/2007005-03).

The licensee took immediate corrective actions to address the issue, and at the end of

the inspection period the licensee continued to evaluate the causes associated with this

finding.

.3

Operability Evaluations

a.

Inspection Scope

The inspectors reviewed selected operability evaluations associated with issues entered

into the licensees corrective action program. The inspectors reviewed design basis

information, the FSAR, TS requirements, and licensee procedures to determine the

technical adequacy of the operability evaluations. In addition, the inspectors determined

whether compensatory measures were implemented, as required. The inspectors

assessed whether system operability was properly justified and that the system

remained available, such that no unrecognized increase in risk occurred.

22

Enclosure

The reviews of the following operability evaluations constituted four samples:

CAP 00889745, Degraded Grid Voltage Concerns;

CAP 01111251, Discrepancy in Control Room Accident Fan Brake Horsepower

Versus Vendor Data Used in Calculation 2004-0002, Revision 6;

CAP 01114308, Unit 1 and 2 Safety Injection Valves 850A/B, Sump B Suction

Valve Limit Switches; and

CAP 01116453, Unit 2 W-3B Control Rod Drive Shroud Fan Tripped on

Overcurrent.

b.

Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications (71111.17)

.1

Annual Resident Review

a.

Inspection Scope

The following engineering design package was reviewed and selected aspects were

discussed with engineering personnel:

EDG G-01 and G-02 heat exchanger modification

This document and related documentation were reviewed to assess adequacy of the

associated 10 CFR 50.59 safety evaluation screening; consideration of design

parameters; implementation of the modification; post-modification testing, and proper

updating of procedures, design, and licensing documents. The inspectors observed

ongoing and completed work activities to verify that installation was consistent with the

design control documents. The modifications were installed to address a longstanding

operator workaround for lake grass fouling of the heat exchangers.

This inspection constituted one sample.

b.

Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19)

a.

Inspection Scope

During completion of the post-maintenance test inspection procedure samples, the

inspectors observed in-plant activities and reviewed procedures and associated records

to determine whether:

Testing activities satisfied the test procedure acceptance criteria;

Effects of the testing were adequately addressed prior to the testing;

Measuring and test equipment calibration was current;

Test equipment was within the required range and accuracy;

23

Enclosure

Applicable prerequisites described in the test procedures were satisfied;

Affected systems or components were removed from service in accordance with

approved procedures;

Testing activities were performed in accordance with the test procedures and

other applicable procedures;

Jumpers and lifted leads were controlled and restored where used;

Test data and results were accurate, complete, and valid;

Test equipment was removed after testing;

Equipment was returned to a position or status required to support the operability

of the system in accordance with approved procedures; and

All problems identified during the testing were appropriately entered into the

corrective action program.

The activities listed below were reviewed by the inspectors and constituted three

quarterly inspection procedure samples:

Unit 1 Charging Pump P-2A;

Unit 1 Charging Pump P-2B Variable Frequency Drive; and

Service Water Pump P-32E.

b.

Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a.

Inspection Scope

During completion of the inspection procedure samples, the inspectors observed in-plant

activities and reviewed procedures and associated records to determine whether:

Preconditioning occurred;

Effects of the testing were adequately addressed by control room personnel or

engineers prior to the commencement of the testing;

Acceptance criteria were clearly stated, demonstrated operational readiness, and

were consistent with the system design basis;

Plant equipment calibration was correct, accurate, and properly documented; as-

left setpoints were within required ranges; and the calibration frequency were in

accordance with TSs, the FSAR, procedures, and applicable commitments;

Measuring and test equipment calibration was current;

Test equipment was used within the required range and accuracy;

Applicable prerequisites described in the test procedures were satisfied;

Test frequencies met TS requirements to demonstrate operability and reliability;

Tests were performed in accordance with the test procedures and other

applicable procedures;

Jumpers and lifted leads were controlled and restored where used;

Test data and results were accurate, complete, within limits, and valid;

Test equipment was removed after testing;

24

Enclosure

Where applicable for IST activities, testing was performed in accordance with the

applicable version of Section XI, American Society of Mechanical Engineers

Code, and reference values were consistent with the system design basis;

Where applicable, test results not meeting acceptance criteria were addressed

with an adequate operability evaluation or the system or component was

declared inoperable;

Where applicable for safety-related instrument control surveillance tests,

reference setting data were accurately incorporated in the test procedure;

Where applicable, actual conditions encountering high resistance electrical

contacts were such that the intended safety function could still be accomplished;

Prior procedure changes had not provided an opportunity to identify problems

encountered during the performance of the surveillance or calibration test;

Equipment was returned to a position or status required to support the

performance of its safety functions; and

All problems identified during the testing were appropriately documented and

dispositioned in the corrective action program.

During this inspection period, the inspectors completed the following inspection

procedure samples, which included two routine surveillances, two inservice tests, and

one containment isolation valve test, for a total of five quarterly inspection procedure

samples:

EDG G01 surveillance testing during the week of October 22, 2007;

Unit 2 TDAFW pump 2P-29 ISTs on November 1 and 2;

Unit 2 TDAFW pump 2P-29 ISTs on November 7;

EDG G02 surveillance testing during the week of November 11; and

Testing of Unit 2 containment isolation valve SC-966.

b.

Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications (71111.23)

a.

Inspection Scope

The inspectors reviewed the following temporary modification:

Furmanite injection of Unit 2 Moisture Separator Reheater Purge

Valve 2MS-32A.

The inspectors compared the temporary configuration changes and associated

10 CFR 50.59 screening and evaluation information against the design basis, the FSAR,

and the TS, as applicable, to verify that the modification did not affect the operability or

availability of the affected system. The inspectors also compared the licensees

information to operating experience information to ensure that lessons learned from

other utilities had been incorporated into the licensees decision to implement the

temporary modification. The inspectors, as applicable, performed field verifications to

ensure that the modifications were installed as directed; the modifications operated as

expected; modification testing adequately demonstrated continued system operability,

25

Enclosure

availability, and reliability; and that operation of the modifications did not impact the

operability of any interfacing systems. Lastly, the inspectors discussed the temporary

modification with operations, engineering, and training personnel to ensure that the

individuals were aware of how extended operation with the temporary modification in

place could impact overall plant performance.

This inspection constituted one sample.

b.

Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)

a.

Inspection Scope

The inspectors performed a screening review of the 2006 and 2007 revisions to the

Point Beach Emergency Plan Manual to determine whether the changes decreased the

plans effectiveness. This review did not constitute an approval of the changes, and as

such, the changes are subject to future NRC inspection to ensure that the emergency

plan continues to meet NRC regulations.

These activities completed one inspection sample.

b.

Findings

No findings of significance were identified

2.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

.1

Inspection Planning

a.

Inspection Scope

The inspectors reviewed the FSAR to identify applicable radiation monitors associated

with measuring transient high and very high radiation areas, including those intended for

remote emergency assessment. The inspectors identified the types of portable radiation

detection instrumentation used for job coverage of high radiation area work, including

instruments used for underwater surveys, portable and fixed area radiation monitors

used to provide radiological information in various plant areas, and continuous air

monitors used to assess airborne radiological conditions and, consequently, work areas

with the potential for workers to receive a 50 millirem or greater committed effective dose

equivalent (CEDE). Whole body counters used to monitor for internal exposure and

those radiation detection instruments utilized to conduct surveys for the release of

personnel and equipment from the radiologically controlled area (RCA), including

contamination monitors and portal monitors, were also identified.

26

Enclosure

These reviews represented two inspection samples.

b.

Findings

No findings of significance were identified.

.2

Walkdowns of Radiation Monitoring Instrumentation

a.

Inspection Scope

The inspectors conducted walkdowns of selected area radiation monitors (ARMs) in the

Unit 1 and Unit 2 auxiliary building to determine if these monitors were located and

provided measurement capability as described in the FSAR and were optimally

positioned relative to the potential sources of radiation they were intended to monitor.

Walkdowns were conducted of those areas where portable survey instruments were

source checked and maintained for radiation protection (RP) staff use to determine if

those instruments designated ready for use were sufficient in number to support the

RP program, had current calibration stickers, were operable, and were in adequate

physical condition. Also, the inspectors observed the licensees portable survey

instrument calibration units and the radiation sources used for operability checks of

various radiation measuring instruments to assess their material condition and discussed

their use with RP staff to determine if they were used appropriately. Additionally, the

inspectors observed the use of the instrument calibration units, discussed with the staff

calibrator output validation methods, and compared calibrator exposed readings with

calculated/expected values. The inspectors evaluated compliance with licensee

procedures while RP personnel demonstrated the methods for performing source checks

of portable survey instruments and source checks of personnel contamination and portal

monitors located at the egress to the RCA and the plant protected area.

These reviews represented one partial inspection sample, which combined with

Section 2OS3.3 constituted one sample.

b.

Findings

No findings of significance were identified.

.3

Calibration and Testing of Radiation Monitoring Instrumentation

a.

Inspection Scope

The inspectors selectively reviewed radiological instrumentation associated with

monitoring transient high and/or very high radiation areas, instruments used for remote

emergency assessment, and radiation monitors used to identify personnel contamination

and for assessment of internal exposures to verify that the instruments had been

calibrated as required by the licensees procedures, consistent with industry and

regulatory standards. The inspectors also reviewed alarm setpoints for selected ARMs,

for personnel contamination monitors and for portal (egress) monitors to verify that they

were established consistent with the FSAR or TSs, as applicable, and were consistent

with industry practices and regulatory guidance. Specifically, the inspectors reviewed

calibration procedures and the most recent calibration records for the following radiation

monitoring instrumentation and calibration equipment:

27

Enclosure

Unit 1 and Unit 2 Containment High Range (Accident) Radiation Monitors;

Unit 1 and Unit 2 Charging Pump Room Low and High Range ARMs;

Unit 1 and Unit 2 Seal Table ARMs;

Unit 1 and Unit 2 Post-Accident Sample Line Monitors;

Common Unit Safety Injection Pump Room Low and High Range ARMs;

Portable Gamma and Neutron Survey Instruments (Model AMP-100 and ASP-1);

Portable Air Sampler (Model AMS-4);

Portal (Gamma) Monitors Used at RCA and Protected Area Egresses;

Personnel Contamination Monitors Used at RCA Egress;

Two Instrument Calibrators (and the associated instruments used to measure

calibrator output); and

Whole Body Counter.

The inspectors determined what actions were taken when, during calibration or source

checks, an instrument was found significantly out of calibration or exceeded as-found

acceptance criteria. Should that occur, the inspectors verified that the licensees actions

would include a determination of the instruments previous uses and the possible

consequences of that use since the prior calibration. The inspectors also reviewed the

results of the licensees most recent 10 CFR Part 61 source term (radionuclide mix)

evaluation to determine if instrument/monitor calibration and check sources were

representative of the plant source term. Given that source term, the inspectors reviewed

the licensees method for internal dose assessment to determine if difficult to detect

nuclides were scaled into whole body count dose determinations.

These reviews represented one partial inspection sample, which combined with

Section 2OS3.2 constituted one sample.

b. Findings

No findings of significance were identified.

.4

Problem Identification and Resolution

a.

Inspection Scope

The inspectors reviewed corrective action documents and any special reports that

involved personnel contamination monitor alarms due to personnel internal exposures to

determine whether identified problems were entered into the corrective action program

for resolution. Licensee self-assessments, audits, and corrective action documents were

also reviewed to determine if problems with radiological instrumentation or with self-

contained breathing apparatus (SCBA) were identified, characterized, prioritized, and

resolved effectively using the corrective action program.

While no internal exposure with a CEDE greater than 50 millirem occurred since the last

inspection in this area, the inspectors reviewed the licensees methodology for internal

dose assessment.

The inspectors reviewed corrective action program reports related to exposure-

significant radiological incidents that involved radiation monitoring instrument

deficiencies since the last inspection in this area, as applicable. Members of the RP

staff were interviewed and corrective action documents were reviewed to determine

28

Enclosure

whether follow-up activities were being conducted in an effective and timely manner

commensurate with their importance to safety and risk based on the following:

Initial problem identification, characterization, and tracking;

Disposition of operability/reportability issues;

Evaluation of safety significance/risk and priority for resolution;

Identification of repetitive problems;

Identification of contributing causes;

Resolution of Non-Cited Violations tracked in the corrective action program; and

Identification and implementation of effective corrective actions.

The inspectors determined if the licensees self-assessment and audit activities

completed for the approximate two-year period that preceded the inspection were

identifying and addressing repetitive deficiencies or significant individual deficiencies in

problem identification and resolution, as applicable.

These reviews represented three inspection samples.

b.

Findings

No findings of significance were identified.

.5

RP Technician Instrument Use

a.

Inspection Scope

The inspectors selectively determined whether calibrations for those survey instruments

used to perform job coverage surveys and for those currently designated for use had not

lapsed. The inspectors reviewed instrument issue logs for selected dates in 2007 to

determine if response checks of portable survey instruments and checks of instruments

used for unconditional release of materials and workers from the RCA were completed

prior to instrument use, or daily, as required by the licensees procedure. The inspectors

also discussed instrument calibration methods and source response check practices

with radiation protection staff and observed staff demonstrate instrument source checks.

These reviews represented one inspection sample.

b.

Findings

No findings of significance were identified.

.6

SCBA Maintenance/Inspection and Emergency Response Staff Qualifications

a.

Inspection Scope

The inspectors reviewed aspects of the licensees respiratory protection program for

compliance with the requirements of Subpart H of 10 CFR Part 20 and to determine if

SCBA equipment was properly inspected, maintained, and ready for emergency use.

The inspectors reviewed records of inspection and functional tests performed in 2006

and 2007 for all SCBAs staged in the plant to support both the licensees fire brigade

and emergency response organization, as provided in the Point Beach Emergency Plan.

29

Enclosure

The inspectors evaluated the licensees capabilities for refilling and transporting SCBA

air bottles to and from the control room during emergency conditions. The inspectors

determined if control room staff designated for the active on shift duty roster were

trained, respirator fit-tested, and medically certified to use SCBAs. Additionally, the

inspectors reviewed SCBA qualification records for the licensees radiological

emergency teams, including the radiation protection, chemistry, and maintenance staffs,

to determine if a sufficient number of staff were qualified to fulfill emergency response

positions consistent with the Emergency Plan and the requirements of 10 CFR 50.47.

The inspectors also reviewed the respiratory protection training lesson plan to assess its

overall adequacy relative to Subpart H of 10 CFR Part 20.

The inspectors walked down SCBA equipment maintained in the control room, the

Operations Support Center, various areas of the turbine building and in the warehouse

fire brigade ready rooms, as well as spare SCBA air bottle stations. During these

walkdowns, the inspectors examined numerous SCBA units to assess their material

condition and to determine if air bottle hydrostatic tests were current and if bottles were

pressurized to meet procedural requirements. The inspectors reviewed records of

SCBA equipment inspection and functional testing, including results of the most recent

regulator flow tests for all SCBA units maintained at the site. Additionally, the inspectors

observed members of the licensees operations and RP staffs demonstrate the methods

used to conduct the inspections and functional tests to determine if these activities were

performed consistent with procedure and the equipment manufacturers

recommendations. The inspectors also evaluated through record review and

observations if the required air cylinder hydrostatic testing was documented and current,

if the Department of Transportation required retest air cylinder markings were in place

for numerous randomly selected SCBA units and spare air bottles, and if air quality for

the compressor used to fill SCBA air bottles was routinely tested to verify Grade-D

quality. The inspectors also reviewed the qualification documentation (training

certificate) issued by the SCBA manufacturer to an individual contracted by the licensee

to perform maintenance/repair of SCBA vital components. Pressure regulator test/repair

records for 2007 for all SCBA units designated for emergency use were reviewed to

determine if the equipment was adequately maintained consistent with the

manufacturers maintenance procedure.

These reviews represented two inspection samples.

b.

Findings

No findings of significance were identified.

4.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification (71151)

.1

Data Submission Issue

a.

Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the 4th

quarter 2007 PIs for any obvious inconsistencies prior to its public release in accordance

with IMC 0608, Performance Indicator Program.

30

Enclosure

This review was performed as part of the inspectors normal plant status activities and,

as such, did not constitute a separate inspection sample.

b.

Findings

No findings of significance were identified.

.2

Mitigating Systems Performance Index - Emergency AC Power System

a.

Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance

Index (MSPI) Emergency AC Power System PIs, for both Units, for July 2006 through

March 2007. To determine the accuracy of the data the inspectors used definitions and

guidance in Revision 5 of the Nuclear Energy Institute (NEI) Document 99-02,

Regulatory Assessment Performance Indicator Guideline. The inspectors reviewed the

licensees operator narrative logs, MSPI derivation reports, issue reports, event reports,

and NRC integrated inspection reports for July 1, 2006, to March 31, 2007, to validate

the accuracy of the submittals. The inspectors reviewed the MSPI component risk

coefficient to determine if it had changed by more than 25 percent since the previous

inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any

problems had been identified with the PI data collected or transmitted for this indicator;

were identified.

This inspection constituted two MSPI emergency AC power system samples.

b.

Findings

No findings of significance were identified.

.3

Mitigating Systems Performance Index - High Pressure Injection Systems

a.

Inspection Scope

The inspectors sampled licensee submittals for the MSPI - High Pressure Injection

Systems PIs, for both Units, for July 2006 through March 2007. To determine the

accuracy of the PI data the inspectors used definitions and guidance contained in

NEI 99-02. The inspectors reviewed the licensees operator narrative logs, issue

reports, MSPI derivation reports, event reports, and NRC integrated inspection reports

for July 1, 2006 to March 31, 2007, to validate the accuracy of the submittals. The

inspectors reviewed the MSPI component risk coefficient to determine if it had changed

by more than 25 percent since the previous inspection, and if so, that the change was in

accordance with applicable NEI guidance. The inspectors also reviewed the licensees

issue report database to determine if any problems had been identified with the PI data

collected or transmitted for this indicator and none were identified.

This inspection constituted two MSPI high pressure injection system samples.

31

Enclosure

b.

Findings

No findings of significance were identified.

.4

Mitigating Systems Performance Index - Heat Removal System

a.

Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Heat Removal System PI, for

both Units, for July 2006 through March 2007. To determine the accuracy of the PI data

reported during that period, the inspectors used PI definitions and guidance in

NEI 99-02. The inspectors reviewed the licensees operator narrative logs, issue

reports, event reports, MSPI derivation reports, and NRC integrated inspection reports

for July 1, 2006, to March 31, 2007, to validate the accuracy of the submittals. The

inspectors reviewed the MSPI component risk coefficient to determine if it had changed

by more than 25 percent since the previous inspection, and if so, that the change was in

accordance with applicable NEI guidance. The inspectors also reviewed the licensees

issue report database to determine if any problems had been identified with the PI data

collected or transmitted for this indicator and none were identified.

This inspection constituted two MSPI heat removal system samples.

b.

Findings

No findings of significance were identified.

.5

Mitigating Systems Performance Index - Residual Heat Removal System

a.

Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Residual Heat Removal

System PI, for both Units, for July 2006 through March 2007. To determine the accuracy

of the PI data reported during that period the inspectors used definitions and guidance in

NEI 99-02. The inspectors reviewed the licensees operator narrative logs, issue

reports, MSPI derivation reports, event reports, and NRC integrated inspection reports

for July 1, 2006, to March 31, 2007, to validate the accuracy of the submittals. The

inspectors reviewed the MSPI component risk coefficient to determine if it had changed

by more than 25 percent in value since the previous inspection, and if so, that the

change was in accordance with applicable NEI guidance. The inspectors also reviewed

the licensees issue report database to determine if any problems had been identified

with the PI data collected or transmitted for this indicator and none were identified.

This inspection constituted two MSPI residual heat removal system samples.

b.

Findings

No findings of significance were identified.

32

Enclosure

.6

Mitigating Systems Performance Index - Cooling Water Systems

a.

Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Cooling Water Systems PI for

July 2006 through March 2007. To determine the accuracy of the PI data reported

during those periods, the inspectors used definitions and guidance in NEI 99-02. The

inspectors reviewed the licensees operator narrative logs, issue reports, MSPI

derivation reports, event reports, and NRC integrated inspection reports for July 1, 2006,

to March 31, 2007, to validate the accuracy of the submittals. The inspectors reviewed

the MSPI component risk coefficient to determine if it had changed by more than

25 percent since the previous inspection, and if so, that the change was in accordance

with applicable NEI guidance. The inspectors also reviewed the licensees issue report

database to determine if any problems had been identified with the PI data collected or

transmitted for this indicator and none were identified.

This inspection constituted two MSPI cooling water system samples.

b.

Findings

No findings of significance were identified.

.7

Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent

Occurrences

a.

Inspection Scope

The inspectors used definitions and guidance contained in Revision 5 of NEI 99-02

to verify the accuracy of the data for the Radiological Effluent Technical

Specification/Offsite Dose Calculation Manual (RETS/ODCM) Radiological Effluent

Occurrence PI.

The inspectors reviewed the licensees CAP database and selected individual condition

reports generated between December 2006 and November 2007 to identify any potential

occurrences such as unmonitored, uncontrolled, or improperly calculated effluent

releases that may have impacted offsite dose. The inspectors also selectively reviewed

gaseous and liquid effluent summary data and the results of associated offsite dose

calculations for selected periods in 2007 to determine if indicator results were accurately

reported. The inspectors also discussed with the licensee the methods for quantifying

gaseous and liquid effluents and for determining effluent dose.

These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

33

Enclosure

4OA2 Problem Identification and Resolution (71152)

.1

Routine Resident Inspector Review

a.

Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewed

issues during baseline inspection activities and plant status reviews to determine

whether issues were entered into the licensees corrective action program at an

appropriate threshold, that adequate attention was given to timely corrective actions, and

that adverse trends were identified and addressed. The inspectors also reviewed all

CAPs written during the inspection period. The CAPs written by the licensee as a result

of inspectors observations are included in the list of documents in the Attachment to this

report.

b.

Findings

No findings of significance were identified.

.2

Selected Issue Follow-up Inspection: Annual Review of Operator Workarounds

Introduction

The inspectors selected operator workarounds for a more in-depth review in accordance

with Inspection Procedure requirements.

This annual review of operator workarounds constituted one inspection sample.

a.

Effectiveness of Problem Identification

(1) Inspection Scope

The inspectors reviewed plant logs, condition reports, and work requests to verify that

the licensees identification of operator workarounds was complete, accurate, and timely,

and that the consideration of extent of condition review, generic implications, common

cause, and previous occurrences was adequate.

(2) Findings and Issues

No findings of significance were identified. No issues were identified.

b.

Prioritization and Evaluation of Issues

(1) Inspection Scope

The inspectors reviewed plant logs, condition reports, and work requests associated with

existing operator burdens, including operator workarounds, operator challenges, and

control room deficiencies. The nature and significance of individual issues and all issues

in aggregate with respect to safety, risk, and licensee corrective action procedural

requirements were considered. Additionally, the inspectors assessed the licensees

evaluation and disposition of performance issues, evaluation and disposition of

operability issues, and application of risk insights for prioritization of issues.

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Enclosure

(2) Findings and Issues

No findings of significance were identified. No issues were identified.

c.

Effectiveness of Corrective Actions

(1) Inspection Scope

The inspectors reviewed condition reports and work requests associated with existing

operator workarounds, operator challenges, and control room deficiencies to determine if

the licensees corrective action program addressed generic implications. Additionally,

the inspectors verified that established corrective actions by the licensee were

appropriately focused to correct the problem.

(2) Findings and Issues

No findings of significance were identified. No issues were identified.

.3

Semiannual Trend Review

a.

Inspection Scope

The inspectors reviewed of the licensees CAPs and associated documents to identify

trends that could indicate the existence of a more significant safety issue. The

inspectors review was focused on repetitive equipment issues, but also considered the

results of daily inspector CAP item screening discussed in Section 4OA2 above,

licensee trending efforts, and licensee human performance results. The inspectors

review nominally considered July 2007 through December 2007, although some

examples expanded beyond those dates.

The reviews also included issues documented outside the normal corrective action

program in major equipment problem lists, repetitive and/or rework maintenance lists,

departmental problem/challenges lists, system health reports, quality assurance

audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the

licensees corrective action program trending reports. Corrective actions associated with

a sample of the issues identified in the licensees trending reports were reviewed for

adequacy.

This semi-annual trend review by the inspectors constituted one inspection.

b.

Findings and Issues.

No findings of significance were identified. No issues were identified.

35

Enclosure

4OA3 Followup of Events and Notices of Enforcement Discretion (71153)

.1

TS-Required Shutdown Due to High Unit 2 Refueling Water Storage Tank Temperature

a.

Inspection Scope

Through record reviews and discussion with plant staff, the inspectors assessed the

circumstances of a TS-required shutdown initiated on September 18, 2007. Although

the licensee took immediate corrective actions to de-energize the submersion heaters

and cool the RWST by forced recirculation, the temperature could not be restored to

acceptable limits before the eight-hour TS action statement expired. As a result, Unit 2

commenced a TS-required shutdown that was later averted, while at approximately

20 percent reactor power, when the RWST temperature was restored to within

acceptable limits. The inspection scope included a review of the events leading up to

the shutdown initiation.

b. Findings

Introduction: A self-revealing finding of very low safety significance (Green) and an

associated Non-Cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, was identified for the failure to allow operators

to properly set the thermostat of the Unit 2 RWST heaters, and to ensure that the RWST

was recirculated frequently enough for the temperature indicator to accurately measure

bulk temperature.

Description: On September 18, 2007, during the performance of TS-required

surveillance SR 3.5.4.1, the Unit 2 RWST was found to be at 105 °F. The TS

maximum allowable limit was 100 °F (97 °F parametric). Because RWST temperature

could not be restored within the allowed eight hours, operators commenced a shutdown

of Unit 2. At 20 percent power, the temperature was returned to within acceptable limits

and the operators began to raise reactor power to 100 percent. The cause of the

elevated temperature was found to be the incorrectly set RWST heater thermostat.

It was identified that on August 30, the controlling thermostat for the RWST heaters was

incorrectly set to 95 °F vice 50 °F as required by procedure. For the 18 days between

August 30 and September 18, the bulk water temperature increased to 105 °F through

natural circulation. During this period, daily temperature readings of the RWST only

showed an increase from 75 °F to 85 °F. This disparity occurred due to stratification

caused by the location of the single temperature indicator relative to the heaters inside

the tank. Because the RWST temperature indicator is located 2 feet from the bottom of

the 70 foot tall tank, and the heaters are located 4.5 feet above the indicator,

stratification caused the temperature indicator to remain in a layer of colder water. It

was not until September 18, that the RWST temperature was found to be at 105 °F, after

four hours of being on forced recirculation.

The inspectors reviewed procedure PC 49, part 4, Revision 19, which was used for

setting the thermostat on the RWSTs to 50 °F. This task was performed once a year

during cold weather preparations to ensure that the RWST remained within the required

temperature range of 40 to 100 °F. Through this review, the inspectors concluded that a

lack of sufficient detail existed for the critical step of setting the thermostat, which directly

affected the operability of the safety-related RWST. Specifically, the lack of procedural

36

Enclosure

detail contributed to the operators reliance upon an unapproved operator aid in the field;

in this case, a black marking that was believed by the operator to indicate the desired

thermostat setting.

The inspectors also reviewed procedure PC 25, Revision 23, which was used to

recirculate and purify the RWST. This task was performed to keep the RWST contents

in a homogeneous mixture to prevent stratification. Through this review, the inspectors

concluded that the frequency of RWST recirculation, which was performed monthly, was

inadequate to ensure that the temperature indicator accurately read bulk tank

temperature to satisfy the TS operability requirements, while the heaters were

energized.

Analysis: The inspectors determined that the failure to have adequate procedures in

place to ensure the operability of the safety related RWST is a performance deficiency

and a finding. The finding is more than minor in accordance with IMC 0612, Power

Reactor Inspection Reports, Appendix B, Issue Screening, dated September 20, 2007,

because it is associated with the procedural quality and human performance attributes of

the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring

the availability, reliability, and capability of systems that respond to initiating events to

prevent undesirable consequences.

Using IMC 0609, Significance Determination Process, dated January 10, 2008, the

inspectors determined that the finding is of very low safety significance (Green) because

the finding did not involve a design deficiency, there was no actual loss of safety

function, no single train loss of safety function for greater than the TS allowed outage

time, and no risk due to external events. The inspectors also determined that the finding

had a cross-cutting aspect in the area of human performance. Specifically, human error

prevention techniques were not utilized prior to and during the thermostat setting task

and personnel proceeded in the face of uncertainty and unexpected circumstances

(H.4(a)).

Enforcement: 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and

Drawings, requires, in part, that activities affecting quality 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 and drawings.

Contrary to this, the licensees procedure PC 49, part 4, used for setting the RWST

heater thermostat, did not have adequate instructions for correctly setting the

thermostat. Further, the monthly recirculation of the RWST, specified in procedure

PC-25, was not appropriate to ensure that the TS-required temperature readings were

valid in their indication of bulk tank temperature while heaters were energized. Because

of the very low safety significance of this finding and because the finding was entered

into the licensees corrective action program (CAP 01111841), the violation is being

treated as an NCV, consistent with Section VI.A.1 of NRC Enforcement Policy

(NCV 05000266/2007005-04; 05000301/2007005-04).

The licensee entered the event into its corrective unit action program, took corrective

actions to increase the frequency of the Unit 1 and Unit 2 RWST recirculation to once

every seven days until the heaters were no longer needed due to seasonal temperature

increases, and conducted a root cause evaluation.

37

Enclosure

.2

(Closed) Violation (VIO)05000266/2006011-01; 050000301/2006011-01: Failure to

Update Final Safety Analysis Report with Reactor Head Drop Analysis and Obtain NRC

Approval

The inspectors evaluated the licensees corrective action program responses to the

January 29, 2007, Notice of Violation associated with the NRC Special Inspection Report

05000266/2006011; 05000301/2006011, for issues in the spring of 2005, regarding a

1982 reactor vessel head drop analysis. The inspectors reviewed the corrective actions

the licensee described in its correspondence dated December 19, 2006, entitled,

Response to an Apparent Violation in Inspection Report05000266/2006011;

05000301/2006011; EA-06-274. The inspectors validated the following corrective

actions were complete: incorporation of the Reactor Vessel Head Drop Analyses into

the FSAR; revision of the Technical Requirements Manual Section 3.9.4; revision of

plant procedures, including maintenance, outage, and operations procedures and

checklists; development of a licensing basis policy and training for plant staff on that

policy; development and implementation of a continuing training module for plant

engineers; licensee evaluation and validation of commitments contained in an

October 1996 NRC, Request for Information Pursuant to 10 CFR 50.54(f) Regarding

Adequacy and Availability of Design Basis Information, with corresponding corrective

actions for identified deficiencies; and development of a procedure writer/reviewer

certification matrix with a job familiarization guide which addressed how to search the

sites regulatory information system. The review by the inspectors constituted one

inspection procedure sample.

4OA5 Other Activities

.1

(Closed) Unresolved Item (URI) 05000266/2007008-06: Inadequate Post-Maintenance

Testing (PMT) of the Turbine-Driven Auxiliary Feedwater Pumps Following Major

Maintenance

Introduction: The inspectors identified a finding of very low safety significance (Green)

and an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, for the licensees failure to conduct adequate

PMT of the Unit 1 1P-29 TDAFW pump following a ten-year overhaul of the turbine in

May 2007. Specifically, the ten-year overhaul maintenance included bearing

replacement, but, the PMT did not run the TDAFW pump long enough for bearing

temperature to stabilize. The appropriate PMT would have detected that the bearing

temperatures were rising and required evaluation prior to declaring the TDAFW

operable.

Description: The licensee completed an overhaul of the Unit 1 TDAFW turbine and the

associated PMT on May 6, 2007, declaring the TDAFW pump operable following

completion of quarterly IST procedure IT-8A. The PMT requirements for the overhaul

were listed in the maintenance overhaul procedure, RMP 9044-1. The IST procedure

had no specific requirements to monitor bearing temperatures for stabilization other than

to perform the IST, which recorded bearing temperature data. The procedure did have a

temperature limit to place the pump in the alert range and conduct an engineering

evaluation when the turbine outboard bearing exceeded 225 °F, and to remove the

pump from service and declare the pump inoperable when the same bearing exceeded

250 °F. However, as part of the PMT for the ten-year overhaul, there was no

38

Enclosure

requirement in either the work order, maintenance procedure or the IST procedure, to

ensure bearing temperatures were stabilized.

For testing on May 1, the inspectors noted that the outboard bearing temperature

reached 247 °F, as indicated on the chart recorders. During the PMT on May 6, some

licensee personnel noted the turbine outboard bearing rising, but indicated the

temperatures was stabilizing. However, the licensee did not wait for temperature

stabilization and secured the Unit 1 TDAFW pump. The inspectors review of chart

recorders revealed that the outboard bearing temperature was at 238 °F and still rising.

The licensee had declared the TDAFW pump operable with no PMT assessment of the

outboard bearing temperature trend and no engineering analysis or evaluation of the

changes in outboard bearing temperature from prior to the overhaul.

During the Unit 1 TDAFW pump quarterly IST procedure IT-8A performance on June 9,

turbine outboard bearing temperature exceeded 225 °F. The turbine outboard bearing

temperature was at 233 °F and still rising when the pump was secured after the test was

completed. In this case, a CAP was written and a follow-up test was completed on

June 12, with the goal to attain bearing temperature stabilization. The test was stopped

at around 249.5 °F, prior to bearing temperature stabilization, and the 250 °F limit to

secure the pump. The pump was declared inoperable and the plant was subsequently

shutdown to repair the TDAFW turbine.

The licensees root cause evaluation indicated the turbine was improperly assembled

during the overhaul in May 2007. In addition, the inspectors determined that changes to

procedure NP 10.2.7, Post Maintenance/Return to Service Testing, did not occur when

a change in the ASME OM Code in 1998 resulted in removing stabilization criteria from

the normal ISTs for safety-related equipment. Specifically, the procedure allowed credit

to be taken for ISTs; however, the procedure did not alert personnel that ISTs no longer

required temperature stabilization. Procedure NP 10.2.7, did specify that licensee

personnel review the PMT matrix for maintenance tasks performed, and the PMT matrix

specified temperature stabilization for bearing replacements. In addition, the licensee

concluded from the root cause that: people interviewed, who were involved with the

PMT recommendation, approval, and review process rely on the applicable procedure to

be correct and do not verify that the correct PMT is specified in the procedures; many

operations, engineering, and planning personnel rely on memory when assigning PMT to

work that does not have a procedure-based PMT; and additional training may be

necessary for PMT activities.

Past Operability and Availability Analysis

From July through December 2007, the licensee evaluated the past operability and

availability of the Unit 1 TDAFW pump. The inspectors, in conjunction with a technical

matter expert from the Office of Nuclear Reactor Regulation and a Regional Senior

Reactor Analyst, reviewed the licensees past availability analysis, and verified the

assumptions, calculations, and conclusions made by the licensee in AR 01090456, Past

Availability 1P-29 Turbine Driven Auxiliary Feedwater Pump. The inspectors verified

the conclusion made by the licensee that the as-found condition of the turbine would

have resulted in the turbine being able to perform its function for the 24-hour mission

time. The as-found condition consisted of the following known deficiencies caused by

the spring 2007 maintenance: inadequate wheel lap setting, inadequate pump-to-turbine

coupling stretch; inadequate stretch and misalignment in the gear box coupling; and

39

Enclosure

inadequate thrust bearing axial end clearance. The basis for concluding that the

TDAFW pump would have performed its function were as follows: the accumulated run

time without component degradation provided indications of satisfactory operation of

components other than the bearing; the vibration measurements of the turbine and pump

were satisfactory and indicated normal operation; oil analysis for the bearings were

acceptable; IST data for the pump indicated no appreciable difference between the

results prior to and after the overhaul of the turbine; outboard bearing temperatures,

while significantly higher than normal, were determined via analysis by a vendor and

concurrence by the turbine manufacturer to stabilize at a temperature that was

acceptable for a 24-hour mission time; analysis demonstrated that adjacent turbine

components would not be affected by the increased bearing temperature; analysis of the

oil at increased temperatures by the oil vendor demonstrated no significant decrease in

oil properties; and the increased bearing temperatures were evaluated by the bearing

manufacturer and determined not to affect the operation of the bearing for a 24-hour

mission time.

Analysis: The inspectors determined the failure to have adequate PMT of the TDAFW

pumps was a performance deficiency and a finding. Using IMC 0612, Power Reactor

Inspection Reports, Appendix B, Issue Screening, dated September 20, 2007, the

inspectors determined that this finding is more than minor because if left uncorrected,

the failure would become a more significant issue.

Using IMC 0609, Appendix A, Determining the Significance of Reactor Inspection

Findings for At-Power Situations, Attachment 1, SDP Phase 1 Screening Worksheet for

IE, MS, and B Cornerstones, dated January 10, 2008, the inspectors determined that

the finding did not result in an actual loss of safety function of a system or train of

equipment. Therefore, the finding is considered to be of very low safety significance

(Green). The inspectors also determined that this finding had a cross-cutting aspect in

the area of human performance because the licensee did not ensure that procedures

were adequate and accurate to assure nuclear safety (H.2(c)).

Enforcement: 10 CFR 50, Appendix B, Criterion V, requires, in part, that activities

affecting quality be prescribed and accomplished by procedures appropriate to the

circumstances. Contrary to this, the licensee failed to prescribe and accomplish

adequate PMT with procedures appropriate to the circumstances to ensure that

after maintenance on safety-related equipment, the equipment returned to service

in an operable condition, an activity affecting quality. Because this finding was of

very low safety significance (Green) and because the finding was entered into the

licensees corrective action program (as CAP 01090456), this violation is being treated

as a Non-Cited Violation (NCV 05000266/2007005-05; NCV 05000301/2007005-05),

consistent with Section VI.A of the NRC Enforcement Policy.

The licensee took immediate corrective actions to address the issue by revising the

appropriate procedures, and at the end of the inspection period the licensee continued to

implement planned corrective actions.

40

Enclosure

.2

Evaluation of Licensees Organizational Response to the 2P-29 TDAFW Pump

Emergent Issue (95003)

b.

Inspection Scope

The inspectors utilized additional inspection hours allowed by IMC 0305 Operating

Reactor Assessment Program, since Point Beach exited Column IV of the NRCs Action

Matrix in 2007, to assess the licensees organizational response to a significant issue

associated with the Unit 2 2P-29 TDAFW pump in November 2007. In particular, the

inspectors focused on the organizational use of human performance tools, the

performance of operations and engineering personnel during the issue, and utilization of

the corrective action program by the organization.

Increased water in the outboard bearing of TDAFW pump 2P-29 was first observed

in June 2007. The licensee performed an operability evaluation at that time and

concluded that the pump was operable because the concentration of the oil was

below the 5,000 pm threshold value for operability established by the licensee, based

on Electric Power Research Institute (EPRI) and vendor guidance. Test results revealed

in June 2007 that the water concentration was approximately 140 ppm and in July

compensatory testing identified an increase to 760 ppm. The licensee continued to

trend increasing water in the oil and developed a contingency plan. On September 21,

the oil sample results revealed water levels had increased to 3,845 ppm, and during the

2P-29 TDAFW pump run, an outboard high temperature alarm occurred. In addition,

operators noted that additional leakage was observed from the turbine outboard gland

area. The licensee commenced implementation of the contingency plan, which included

a pump overhaul.

The overhaul was completed on September 23, and included replacement of the turbine

shaft carbon seal rings and the turbine outboard gland seal casing. The gland and

turbine casings were then sealed with high temperature silicone per the maintenance

procedure. The TDAFW pump was run and oil samples were collected. The water

content was visually estimated at 1,500 ppm, and the licensee concluded that they were

within the bounds of the previous operability evaluation. A second test run conducted

that day revealed less water visually than the first run. Both samples were sent offsite

for analysis. On September 27, the lab results were received, with the first run showing

20,400 ppm of water and the second run showing only 56 ppm of water. Condition

report CAP 01113318 was written; however, the description discounted the higher

sample based on conformational biases of the personnel involved, specifically: high

room humidity; statements from a vendor representative noting that increased leakage

may be expected following overhauls (even though this had never been seen on the

identical turbine for the opposite unit); and high humidity in the room where the samples

were split for offsite analysis. Consequently, CAP 01113318 was closed with no action

taken.

On November 1, 2P-29 was run twice and the water content in the oil was analyzed

at 29,515 ppm for the first run and 17,700 ppm for the second run, supporting the

September 2007 value of 20,400 ppm of water as a valid result. The licensee

subsequently initiated its event response procedure. Revision 2 of operability

Evaluation OPR01098358 was performed and completed on November 3, and required

a compensatory measure of running the turbine and sampling the oil every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Over the next several days, the TDAFW pump was run for eight hours, every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

41

Enclosure

Additional data and responses by the licensee to the inspectors questions necessitated

three additional revisions of the OPR by November 10. On November 13, due to the

continued high water content, the licensee elected to overhaul the turbine. The licensee,

with vendor assistance, identified the following significant as-found conditions during the

overhaul: a gap in the aluminum oil deflector ring attached to the turbine shaft by a set

screw, that provided a direct path for steam to enter the bearing housing along the

turbine shaft; the silicone sealant, particularly around the gland housing and casing,

exhibited a lack of adhesion, also providing a path for steam entering; and the gland

housing, which was replaced in the September 2007 maintenance, was undersized.

Following the November 2007 overhaul, the pump underwent PMT and the outboard

bearing oil samples showed less than 100 ppm of water.

c.

Findings

The inspectors identified three Green findings with associated NCVs as a result of the

inspection activities. Two findings are documented in this Section and a third is

documented in Section 1R15.2 of this report.

b.1

Failure to Take Adequate Corrective Actions to Address Water Ingress Following

Maintenance

Introduction: The inspectors identified a Non-Cited Violation (NCV) of 10 CFR 50,

Appendix B, Criterion XVI, Corrective Action, having very low safety significance

(Green) for the licensees failure to take prompt corrective actions to correct the cause of

increased water in the 2P-29 TDAFW pump turbine outboard bearing housing, a

condition adverse to quality, originally identified in September 2007.

Description: On September 24, 2007, following the overhaul of the 2P-29 TDAFW

pump turbine, an oil sample was taken from the outboard bearing housing, following a

four hour run. CAP 01112660 was written, which documented water volume in the oil

sample of 1,000 to 1,500 ppm for the four-hour run. The CAP description concluded that

this was an expected condition. A second shorter pump run was performed, and the

water content in the oil was visually estimated to be 100 ppm. The licensee rationalized

that the initial water content was expected and the CAP was closed with no further

actions taken. Three days later, CAP 01113318 was written and documented that the

outboard oil sample from the first four-hour run was actually 20,040 ppm water, and that

the number was not consistent with the visual indications seen on September 24. The

description in the CAP was presented in a manner which refuted the results based on

conjecture, concluding that the 20,040 ppm results were false readings due to a

laboratory error or an accidental capture of water droplets during the sampling process.

The CAP concluded that, the indicated levels of water in the IT-09A sample are errant.

The CAP was screened by licensee staff and no additional actions were taken to either

characterize the cause of the unexplained increase of water in the oil, or to further

evaluate this unexpected condition identified through testing of the safety-related oil,

following the four-hour TDAFW pump run. The licensee did not consider as a corrective

action, running the pump and obtaining another oil sample to verify that the abnormally

high water content following the overhaul was a false indication.

On November 1, approximately five weeks after the maintenance overhaul, the licensee

ran 2P-29 and sampled the oil. The frequency of running the pump once per month was

established in June 2007, when the moisture in the turbine outboard bearing oil was

42

Enclosure

significantly less than the EPRI and vendor recommended 5,000 ppm. The pump was

run slightly more than two hours and the outboard oil sample drawn revealed 29,515

ppm of water in the oil. After the pump had not run for about eight hours and was then

run for eight hours, 17,700 ppm was found in the outboard bearing oil. The licensee

declared the pump inoperable and revised the original June 2007 operability evaluation.

As described previously, on November 13, the licensee began an overhaul of the

turbine.

The inspectors determined that the original unsatisfactory oil sample results in

September 2007 identified a condition adverse to quality associated with the

safety-related 2P-29 TDAFW pump; however, prompt corrective actions were not taken.

Analysis: The inspectors determined that the licensees failure to implement prompt

corrective actions to address the September 2007 2P-29 TDAFW pump turbine

degraded oil sample results, a condition adverse to quality, was a performance

deficiency and a finding. The inspectors concluded that the finding is more than minor in

accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue

Screening, dated September 20, 2007, in that the finding could reasonably be viewed

as a precursor to a significant event. Specifically, the failure to promptly correct the

cause of the oil degradation in a timely manner could result in failure of the TDAFW

turbine.

The significance of this finding was evaluated using IMC 0609, Appendix A,

Determining the Significance of Reactor Inspection Findings for At-Power

Situations, dated January 10, 2008, for the Mitigating Systems Cornerstone. The

risk assessment for the potential loss of safety function is attributed to the performance

deficiencies associated with inadequate maintenance discussed in Section 4OA5.2.b.2

as URI 5000266/2007005-07. This finding, for the failure to implement prompt corrective

actions, did not cause the loss of safety function for greater than the allowed outage

time. The inspectors determined that the finding is of very low safety significance

(Green), because the finding did not involve a design deficiency, there was no actual

loss of safety function, no single train loss of safety function for greater than the TS

allowed outage time, and no risk due to external events. The licensee concluded that

although the pump was initially declared inoperable and the oil was degraded, the

TDAFW pump would have performed its specified safety function. Additionally, the

inspectors determined that the finding had a cross-cutting area aspect in the area of

problem identification and resolution. Specifically, the licensee failed to thoroughly

evaluate the problem with water ingress into the oil, such that a resolution addressed the

cause and extent of condition (P.1(c)).

Enforcement: 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires, in

part, that measures be established to assure that conditions adverse to quality, such as

malfunctions, deficiencies, deviations, defective equipment and nonconformances are

promptly identified and corrected. Contrary to this, a condition adverse to quality,

associated with the turbine of the Unit 2 TDAFW pump 2P-29 was not promptly

corrected following identification in September 2007. Specifically, upon identification of

degraded oil in September 2007, a condition adverse to quality, the licensee did not take

prompt corrective actions. As a result of the failure to take prompt corrective actions, the

pump was declared inoperable until November 2007, following additional oil samples

that revealed the continued degraded condition. Because of the very low safety

significance of this finding and because it was entered into the licensees corrective

43

Enclosure

action program as CAP 01115748, this violation is being treated as an NCV, consistent

with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000301/2007005-06).

The licensee took immediate corrective actions to address the issue, which included

reevaluation of operability and ultimately overhaul of 2P-29, and at the end of the

inspection period the licensee continued to evaluate the causes associated with this

finding.

b.2

Unresolved Item: Failure to Perform Adequate Maintenance Resulting in Increased

Water Ingress

Introduction: The inspectors identified a URI associated with the licensees failure to

perform adequate maintenance on the Unit 2 TDAFW pump turbine in September 2007.

Description: The elevated moisture content in the outboard bearing for the 2P-29 turbine

was present since the last ten-year overhaul was performed in November 2006.

However, while the moisture content levels in the oil from November 2006 until the

September 21, 2007, overhaul were elevated, the levels were below the 5,000 ppm

value documented as acceptable in EPRI and vendor guidance. Steam leakage from

the gland seal or turbine casing joints prior to the September overhaul would not have

been vented away from the bearing housing since the turbine insulation extended over

the top of the gland seal casing and up to the bearing housing. In addition, original

cement-based insulation also blocked the gland seal area vent holes.

The licensee concluded, based on test data, that the 2P-29 turbine overhaul that was

completed on September 23, 2007, significantly increased the moisture content in the

outboard bearing oil. A silicone seal applied at the gland casing to turbine casing joint

failed upon initial service resulting in a steam leak in the area of the outboard bearing

housing. The failure of the sealant could not be attributed to one factor; however, the

licensee did conclude one of the root causes was its maintenance procedures did not

address the special requirements needed when applying sealants, and, therefore, site

personnel did not have adequate instruction or training on the use of sealants. In

addition, the licensee identified that the September 2007 maintenance did not allow for

the proper cure time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the sealant and exceeded the process time of 30

minutes from when the sealant was applied and the joint was torqued.

In a review of the site maintenance procedures, the licensee also identified an additional

root cause that the site continued to lack adequate guidance on specific assembly

details of the turbine, specifically for the oil deflector ring on the turbine shaft: the

tightening of the oil deflector ring set screw was not discussed; and acceptable

clearances between the turbine shaft and the inner diameter of the oil deflector ring were

not specified.

The licensee identified three additional contributing causes: receipt and installation of a

gland casing from the vendor that had incorrect critical dimensions; previous insulation

work blocked the gland seal vents; and plant personnel did not have adequate guidance

on the installation of insulation. At the end of the inspection period, the licensee

continued to develop and implement corrective actions to address the issues

documented in CAP 01115748.

44

Enclosure

At the conclusion of the inspection, the licensee continued to assess the impact of the

water ingress on the availability of the Unit 2 TDAFW pump to perform its design and

augmented quality functions. There is no current safety concern because the pump was

adequately tested and the current low ingress of water into the bearing housing indicated

that the pumps functionality is currently maintained for all licensing and design basis

events. This issue is an Unresolved Item (URI 05000301/2007005-07) until the NRC

reviews the licensees past availability assessment.

.3

Evaluation of the Licensees Independent Assessment of Engineering (95003)

a.

Inspection Scope

The inspectors utilized additional inspection hours allowed by IMC 0305, since Point

Beach exited Column IV of the NRCs Action Matrix in 2007, to assess the licensees

independent assessment of engineering. The licensee committed as part of its response

to the Confirmatory Action Letter CAL 3-04-001, Revision 1, dated April 14, 2006, to

perform alternating independent and self-assessments of the engineering and corrective

action programs. In July 2007, the licensee performed an independent assessment of

engineering performance. The inspectors reviewed the charter for the assessment,

observed the independent assessment team, reviewed the final report, and reviewed the

proposed corrective actions.

b.

Observations and Assessment

The team consisted of four experienced individuals from other utilities and a consulting

firm. The team assessed licensee engineering performance in five areas: fundamentals

of engineering, equipment reliability, configuration management, corrective actions, and

operating experience. The assessment teams overall conclusions were: engineering

rigor and overall quality has improved and has been sufficient for successful

management of potential challenges to design bases and equipment reliability;

unresolved plant material conditions present substantial ongoing challenges; a plateau

may have been reached for engineering improvement; and additional resources and

continued effort will be required to sustain the improvements that have already been

obtained and to bridge the remaining gaps to engineering excellence.

The assessment team identified the following overall issues for attention: most recent

engineering products are of high quality, but examples of products with less than

adequate rigor are still produced; engineering needs to be more predictable and

accountable with respect to schedules; important longstanding issues were not resolved;

engineering resources may not be adequately matched to engineering obligations; the

preventive maintenance optimization and single point vulnerability projects have

languished and, as a consequence, the station had not benefited from the improved

material condition and safety margins; although a list of low margin issues had been

established, there did not appear to be a quantification of the lost margin associated with

these issues or an evaluation of the cumulative effects; it was not clear that cumulative

effects of conditions adverse to quality were being addressed and the large number of

open conditions presented a challenge to effectiveness of such a review; and the

corrective action process was not used to the full potential, specifically: trending was not

being used as effectively as it could be; more effective use of corrective action

processes for vendor products was warranted; and expectations for a close to fix

solution, versus an apparent cause evaluation warranted examination.

45

Enclosure

The overall recommendations from the assessment team were 1) to maintain highly

visible management commitment to rigor and continue associated empowerment, and

2) to implement the specifically identified corrective actions for issues with predictability,

resolution of longstanding issues, prevent maintenance optimization, cumulative effects

of material condition, more aggressive use of corrective action processes, margin

issues, and engineering resources.

The inspectors confirmed that the licensee had developed plans and corrective actions

to address the issues for attention identified by the Independent Assessment Team.

.4

Evaluation of the Independent Assessment of the Corrective Action Program (95003)

a.

Inspection Scope

The inspectors utilized additional inspection hours allowed by IMC 0305, since Point

Beach exited Column IV of the NRCs Action Matrix in 2007, to assess the licensees

independent assessment of the corrective action program. The licensee committed as

part of its response to the Confirmatory Action Letter CAL 3-04-001, Revision 1, dated

April 14, 2006, to perform alternating independent and self-assessments of the

engineering and corrective action programs. The inspectors reviewed the charter for the

assessment of the corrective action program in August 2007, observed the independent

assessment team, reviewed the final report, and reviewed the proposed corrective

actions.

b.

Observations and Assessment

The team consisted of four experienced individuals from other utilities and a consulting

firm. The team concluded that although measurable improvement in the corrective

action program had been achieved over the last 12 months, several opportunities for

improvement needed to be addressed in order to achieve improved performance. The

team noted the following opportunities for improvement: the effectiveness and quality of

apparent cause evaluations needed to be improved; the number of corrective action

program performance indicators above target with no detailed recovery plan indicated

that timeliness continued to be an issue, corrective action program backlog, in particular,

has been increasing; the ease of CAP initiation via computer (Passport software) and

providing feedback to the CAP initiator for CAPs which are closed by the management

screening committee with no action; trending has not been effective at identifying

adverse trends through the quarterly Department Roll-Up Meetings and Passport issues

continue to impede trending; effectiveness reviews for corrective actions to prevent

recurrence needed to consider effectiveness from a broader perspective; additional

opportunities for improvement were identified in apparent cause evaluations for NRC-

identified findings and on the effectiveness of certain actions specified to correct the

January 2007 corrective action program self-assessment issues.

The independent assessment team concluded that some positive features of the

corrective action program included: management was highly engaged in the program

and the screening committee appears to be highly effective; root cause evaluations were

thorough and comprehensive, and effectiveness review criteria were clearly specified;

format consistency has improved for apparent cause evaluations, effectiveness reviews,

and department roll-up meeting reports; the Performance Assessment Review Board

was involved in reviewing the backlog of open CAPs by department; and most actions

46

Enclosure

taken to address issues from the January 2007 corrective action program self-

assessment had resulted in measurable improvement.

The inspectors confirmed that the licensee had developed plans and corrective actions

to address the opportunities for improvement identified by the Independent Assessment

Team.

.5

(Closed) URI 05000266/2006004-05; 05000301/2006004-05: Inadequate 10 CFR 72.48

Screening to Evaluate Possible Thermal Effects on Fuel Cladding

Introduction: The inspectors identified one violation of 10 CFR 72.48(c)(1) in which the

licensee failed to obtain a Certificate of Compliance (CoC) amendment pursuant to

10 CFR 72.244 for changes made in the spent fuel storage cask operating procedures

during the 2004 loading campaign as described in the FSAR and these changes in the

procedures constituted a change in the terms, conditions, or specifications incorporated

in the CoC. Specifically, although Point Beach changed an operating procedure

described in the FSAR that allowed pump down of water from the dry shielded canister

to occur much earlier in the process; Point Beach failed to identify that the following TS,

which was incorporated in the CoC, would have required changes that needed prior

NRC approval: TS 1.2.17a, 32PT Dry Storage Canister (DSC) Vacuum Drying Duration

Limit.

Description: During the fall 2004 campaign, the licensee used the new NUHOMS 32-PT

cask design and modified the sequence of its loading procedures from the generic

operating procedures stated in Chapter M.8 of the FSAR. The change consisted of

draining all of the water from the canister cavity prior to welding the inner top cover on,

whereas the FSAR prescribed draining some of the water from the canister

(approximately 750 gallons), then welding the top inner cover and then draining the

remainder of the water from the canister. In the 10 CFR 72.48 screening, the licensee

failed to evaluate the effect of the water removal during draining and welding on the fuel

cladding temperature. The inadequate screening failed to identify that TS 1.2.17a,

32 PT DSC Vacuum Drying Duration Limit, which was incorporated in the CoC, would

have required a change that needed prior NRC approval. This amendment to the CoC

would address any affects on the vacuum drying time limits that may result from the

potentially higher fuel cladding temperature. The initial fuel cladding temperature, at the

start of vacuum drying in the procedure that deviated from the FSAR, could be higher

than the FSAR assumed value of 215 °F. An assumed temperature of the fuel cladding

higher than the 215 °F basis in the FSAR may result in a shorter vacuum drying time

than that specified in TS 1.2.17a. The licensee loaded five casks utilizing the different

loading process.

Subsequently, in 2006, the licensees cask vendor, Transnuclear, performed a NUHOMS

32PT drain down evaluation (Calculation No. NU32PT-0420) to address the issues with

the vacuum drying duration limit and fuel cladding temperature. The inspectors

reviewed the calculation, which concluded that the maximum fuel cladding temperature

for the 32PT DSC with a heat load of 16.88 kilowatts (kW) (highest heat load for the

32PT DSC amongst users of this canister at the time) was 720 °F. The 720 °F

temperature was below the allowable limit of 752 °F. Therefore, no time limitation was

necessary for vacuum drying of the 32PT DSC when the total decay heat load was

16.88 kW or below.

47

Enclosure

Transnuclear also performed another evaluation (Calculation NUH32PT-0421) in which it

modeled a loading configuration that resulted in the maximum fuel cladding temperature

for vacuum drying. This loading configuration produced a 22.4 kW total heat load.

TS 1.2.17a stated that the limit for duration of vacuum drying was 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br /> for a 32PT

DSC with a heat load greater than 8.4 kW and up to 24 kW after initiation of vacuum

drying. This value of 22.4 kW total maximum heat load was within the maximum TS fuel

cladding temperature for the 24 kW heat load. The results of this evaluation justified

using a constant temperature of 215 °F for DSC during handling, welding, and vacuum

drying operations, and indicated that after 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br /> of vacuum drying the maximum fuel

cladding temperature was 739 °F, below the allowable limit of 752 °F. The maximum

fuel cladding temperature reached the allowable limit of 752 °F at 67 hours7.75463e-4 days <br />0.0186 hours <br />1.107804e-4 weeks <br />2.54935e-5 months <br /> after the start

of the DSC drainage. Thus, the evaluation concluded that the time limit of 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br /> for

vacuum drying was acceptable.

Analysis: The inspectors determined that the failure to obtain a CoC amendment

pursuant to 10 CFR 72.244 for changes made in the spent fuel storage cask operating

procedures, as described in the FSAR, was a performance deficiency and a finding.

This finding is more than minor because it had the potential to impact the NRCs ability

to perform its regulatory function, since the licensee failed to receive NRC approval for a

change in this licensed activity. A CoC amendment was required since these changes in

the procedures constituted a change in the terms, conditions, or specifications

incorporated into the CoC. The inspectors determined that the finding was not suitable

for SDP evaluation because the noncompliance involved 10 CFR Part 72 dry fuel

storage activities. Therefore, this finding was reviewed by Regional Management and

dispositioned using traditional enforcement.

Enforcement: 10 CFR 72.48(c)(1) states, in part, that a certificate holder may make

changes in the facility or spent fuel storage cask design as described in the FSAR (as

updated), make changes in the procedures as described in the FSAR (as updated),

without obtaining: (a) a Certificate of Compliance (CoC) amendment submitted by the

certificate holder pursuant to 10 CFR 72.244; if: (b) a change in the terms conditions, or

specifications incorporated in the CoC is not required; and (c) the change, test, or

experiment does not meet any of the criteria in paragraph in 10 CFR 72.48(c)(2).

Contrary to this, in an approved 10 CFR 72.48 evaluation, Point Beach failed to obtain a

CoC amendment pursuant to 10 CFR 72.244 for changes made in the spent fuel storage

cask operating procedures as described in the FSAR (as updated) and these changes in

the procedures constituted a change in the terms, conditions, or specifications

incorporated in the CoC. Specifically, although Point Beach changed an operating

procedure described in the FSAR which allowed pump down of water from the dry

shielded canister to occur much earlier in the process; Point Beach failed to identify that

the following TS, which was incorporated in the CoC, would have required changes that

needed prior NRC approval: TS 1.2.17a, 32PT DSC Vacuum Drying Duration Limit.

Because this violation was of very low safety significance, was not repetitive or willful,

and was entered into your corrective action program, this violation is being treated as an

NCV of 10 CFR 72.48(c)(1), consistent with Section VI.A.1 of the NRC Enforcement

Policy (NCV 05000266/2007005-09; 05000301/2007005-09).

The licensee entered the issue into the corrective action program as CAP 01026070 and

implemented corrective actions, including revising the loading procedure to reflect the

sequence described in the FSAR prior to loading the next cask (cask 6).

48

Enclosure

.6

(Closed) URI 07200005/2004003-01: Adequacy of Design Calculation,

PBNP-305336-SO1

During an October through December 2004 NRC inspection, inspectors identified one

URI associated with the adequacy of the licensees auxiliary building structure and the

crane design basis during a seismic event. The licensee received an NCV of

10 CFR 72.122(2)(i), documented in Inspection Report 07200005/2004-003(DNMS),

regarding failure to demonstrate that the crane, a component important to safety, was

designed to withstand the effects of an earthquake without impairing its capability to

perform its intended function. Upon further review, the inspectors identified other

deficiencies in the structural analysis of the building and the crane for which the URI was

opened. There was no response spectra analysis performed on the building to model its

response due to an earthquake at different elevations, such as that of the crane. Also,

the inspectors could not independently verify that the basis for the horizontal

accelerations in all of the calculations used for the auxiliary building and the crane were

adequate. In response to these questions, the licensee constructed a detailed computer

model of the steel portion of the auxiliary building. The preliminary results from an

analysis using this model demonstrated that the original acceleration values were

conservative and adequate to demonstrate compliance with regulations and the ability of

the building and the crane to sustain up to a 125-ton load under an earthquake scenario.

In addition, the licensee hired an independent consultant who confirmed the licensee=s

results. The inspectors were not able to validate these conclusions since the

appropriate documentation was not available at the time of the inspection and a

complete analysis was not completed. However, the licensee committed to perform a

full analysis of the auxiliary building and the crane response under a seismic event with

the current plant conditions.

The licensee performed an analysis of the Class 3 Primary Auxiliary Building (PAB)

Steel Superstructure in Calculation PBNP-305336-SO1, Structural Analysis of Central

PAB with Crane Load of 125 Tons, Revision 1, dated April 3, 2006. During the current

inspection, NRC staff reviewed the calculation results and discussed the assumptions

with licensee personnel. The analysis demonstrated the capability of the structure to

support the crane with a load of 125 tons in case of a seismic event once the welded

connection of the gusset and Columns 10U and 13U were strengthened. Thus, the

calculation verified that the requirements of NUREG-0612 and 10 CFR 72.122(b)(2)(i)

were satisfied. The inspectors concluded that the revised calculation was adequate to

demonstrate compliance with regulations and the ability of the building and the crane to

sustain up to a 125-ton load under an earthquake scenario.

4OA6 MANAGEMENT MEETINGS

.1

Exit Meeting Summary

On January 10, 2008, the inspectors presented the inspection results to Mr. James

McCarthy and other members of the licensee staff. The licensee acknowledged the

issues presented. The inspectors asked the licensee whether any materials examined

during the inspection should be considered proprietary. No proprietary information was

identified.

49

Enclosure

.2

Interim Exit Meeting

An interim exit meeting was conducted for:

Maintenance Effectiveness Periodic Evaluation with Mr. Walt Smith,

Acting Plant Manager on November 2, 2007.

Biennial Licensed Operator Requalification Program Inspection with

Mr. J. McCarthy on November 9, 2007.

Overall assessments of the annual operating test via telephone with

Mr. C. Sizemore on November 21, 2007.

Emergency Preparedness inspection with Ms. Ray and Mr. Tulley on

December 13, 2007.

Occupational radiation safety cornerstone radiation monitoring instrumentation

and protective equipment with Messrs. J. McCarthy and G. Packard and other

licensee staff on December 14, 2007.

ATTACHMENT: SUPPLEMENTAL INFORMATION

1

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

R. Amundson, General Supervisor Operations Supervisor

C. Butcher, Site Engineering Director

G. Casadonte, Fire Protection Coordinator

W. Godes, Training Supervisor

R. Harrsch, Operations Manager

M. Hayes, Radiation Protection Supervisor

C. Jilek, Site Maintenance Rule Coordinator

J. McCarthy, Site Vice-President

G. Packard, Plant Manager

S. Pfaff, Performance Assessment Supervisor

K. Phillips, Outage Manager

M. Ray, Regulatory Affairs Manager

C. Sizemore, Training Manager

T. Schmitt, Lead health Physics Technician

S. Tulley, Emergency Preparedness Manager

B. Vandervelde, Maintenance Manager

D. Villicana, Radiation Protection General Supervisor

G. Young, Nuclear Oversight Manager

Nuclear Regulatory Commission

M. Kunowski, Chief, Reactor Projects, Branch 5

J. Cushing, Point Beach Project Manager, Office of Nuclear Reactor Regulation

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Opened and Closed 05000266/2007005-01; 05000301/2007005-01

FIN

Failure to Control Loose Materials Classified as Tornado

Hazards (Section 1R01.1)05000266/2007005-02; 05000301/2007005-02

FIN

Failure to Adequately Assess Operability of Service Water

Pump P-32C (Section 1R15.1)05000301/2007005-03

NCV

Failure to Perform Operability Evaluations for Turbine-Driven

Auxiliary Feedwater Pump 2P-29 (Section 1R15.2)05000266/2007005-04; 05000301/2007005-04

NCV

Failure to Have Adequate Procedures for the Refueling

Water Storage Tank (Section 4OA3.1)05000266/2007005-05; 05000301/2007005-05

NCV

Failure to Perform Adequate Post-Maintenance Testing for

the Turbine-Driven Auxiliary Feedwater Pumps

(Section 4OA5.1)

2

Attachment 05000301/2007005-06

NCV

Failure to Adequately Evaluate a Condition Adverse to

Quality Associated with Turbine-Driven Auxiliary Feedwater

Pump 2P-29 (Section 4OA5.2.b.1)05000266/2007005-08; 05000301/2007005-08

NCV

Failure to Provide Adequate Guidance to Ensure the

Operability of the MS System During a Steam Generator

Tube Rupture. This Item was described in NRC Inspection

Report 2007301, dated August 21, 2007, as Item Numbers05000266/2007301-01 and 05000301/2007301-01; however,

this item is being repeated in this table for NRC Plant Issues

Matrix tracking.05000266/2007005-09; 05000301/2007005-09

NCV

Inadequate 10 CFR 72.48 Screening to Evaluate Possible

Thermal Effects on Fuel Cladding (Section 4OA5.5)

Opened 05000301/2007005-07

URI

September 2007 Maintenance Activities Associated with

Turbine-Driven Auxiliary Feedwater Pump 2P-29

(Section 4OA5.2.b.2)

Closed 05000266/2006011-01; 05000301/2006011-01

VIO

Failure to Update Final Safety Analysis Report with Reactor

Head Drop Analysis and Obtain NRC Approval

(Section 4OA3.2)05000266/2006004-05; 05000301/2006004-05

URI

Inadequate 10 CFR 72.48 Screening to Evaluate Possible

Thermal Effects on Fuel Cladding (Section 4OA5.5)

07200005/2004003-01

URI

Adequacy of Design Calculation, PBNP-305336-SO1

(Section 4OA5.6)

3

Attachment

LIST OF DOCUMENTS REVIEWED

The following is a partial list of documents reviewed during the inspection. Inclusion on this list

does not imply that the NRC inspector reviewed the documents in their entirety, but rather that

selected sections or portions of the documents were evaluated as part of the overall inspection

effort. Inclusion of a document on this list does not imply NRC acceptance of the document or

any part of it, unless this is stated in the body of the inspection report.

1R01 Adverse Weather Protection

Issue Reports:

- CAP 01114731; Loose Materials Found in the Protected Area; October 19, 2007

- CAP 01114637; Material in Yard; 10/18/2007

- CAP 01094135; Tornado Hazards Identified Performing PC 99; May 25, 2007

- CAP 01102551; Tornado Hazards Identified Performing PC-99; July 19, 2007

- CAP 01112508; Tornado hazards Identified Performing PC-99; September 21, 2007

- CAP 01098214; 3 or More Tornado Hazards in Single Inspection. Area; June 21, 2007

Procedures:

- PC 99; Tornado Hazards Inspection Checklist; Revision 0

- AOP-13C; Severe Weather Conditions; Revision 17

- NP 1.9.6; Plant Cleanliness and Storage; Revision 22

1R04 Equipment Alignment

- CL 11A G01; G01 Emergency Diesel Generator Checklist; Revision 22

- CL 11A G02; G02 Emergency Diesel Generator Checklist; Revision 26

- CL 13, Part 1; Auxiliary Feedwater Lineup Unit 1 Turbine Driven; Revision 36

- CL 13, Part 1; Auxiliary Feedwater Lineup Unit 2 Turbine Driven; Revision 40

- CL 13, Part 1; Auxiliary Feedwater Lineup Motor Driven; Revision 42

- O-SOP-G01-001; Maintenance Operation for Emergency Diesel Generator G01; Revision 5

- O-SOP-G01-002; Maintenance Operation for Emergency Diesel Generator G02; Revision 8

- O-TS-AFW-002; Auxiliary Feedwater System Valve and Lock Checklist - Monthly; Revision 10

1R05 Fire Protection

Fire Hazards Analysis Report; January 2007 Revision

1R07 Heat Sink Performance

Documents:

- Bio/Silt Fouling Inspection Form for EDG G01 Heat Exchanger; November 2007

- Bio/Silt Fouling Inspection Form for EDG G02 Heat Exchanger; December 2007

1R11 Licensed Operator Requalification Program

Issued Reports:

- Point Beach ROP Plant Issue Matrix from 09/01/2005 to 10/11/2007; October 11, 2007

- Point Beach Nuclear Plant, Units 1 and 2 NRC Integrated Inspection Reports; dated various

from October 26, 2005, through October 26, 2007

4

Attachment

- LER 266/2005-007-00; Control Rod Movement With Refueling Cavity Water Level Below

TS 3.9.6 Limit; January 16, 2006

- Nuclear Oversight Assessment Reports for Point Beach; dated various 2006 and 2007

- Operations Training Advisory Committee Meeting Minutes; dated various from

March 15, 2006, through September 13, 2007

- LOR Curriculum Review Committee Meeting Minutes; dated various from March 7, 2006,

through September 28, 2007

- AO Curriculum Review Committee Meeting Minutes; February 21, 2007

- Completed TRQM 19.32; Activation of an Inactive SRO License; Two Separate Forms;

February 24, 2006, and June 5, 2006

- Completed PBF-2094; NRC License Active Status Tracking; dated various

- Completed PBF-6097; Operations Watchstander Temporary Restriction Form; dated various

- Licensed Operator Quarterly Status Report; dated various

- Operations Continuing Training End of Cycle Reports; dated various 2006 and 2007

- QF-1050-01a; Course/Cycle Feedback Summary Form; dated various 2006 and 2007

- 2007 - 2008 LOR Biennial Training Plan (BTP); Revision 3

- 2006 NRC Biennial Written Exams; dated various

- Point Beach Nuclear Plant 2005/2006 Biennial Written Exam Summary

- Point Beach Nuclear Plant 2005/2006 Biennial Written Exam Test Item Statistics

- Point Beach Nuclear Plant 2005/2006 Biennial Written Exam Sample Plan

- Evaluation ID# PB-LOR-006-001E; Written Exam Item Review; August 6, 2007

- Management Observations of Training 2006 and 2007

- Licensee 71111.11 Pre-Inspection; August 13, 2007

- LOR Cycle Attendance Sheets; dated various

- Completed QF-1040-04; Remediation Training Form; dated various

- Completed QF-1040-15; Self-Study/Make-Up Training Form; dated various

- Completed QF-1073-01; Walkthrough Exam Summary; Exam Weeks 5 and 6 of 2007; dated

various

- Completed QF-1073-02; Crew Simulator Evaluation Summary; Exam Weeks 5 and 6 of 2007;

dated various

- Completed QF-1073-03; Individual Operator Simulator Examination Summary; Exam Weeks 5

and 6 of 2007; dated various

- Completed QF-1073-04; Remediation Training Form; Exam Weeks 5 and 6 of 2007; dated

various

- Simulator Review Committee Meeting Minutes; dated various from March 2, 2006, through

September 13, 2007

- FP-T-SAT-81; Simulator Testing and Documentation; Revision 4

- SWO 05-0039; Rehost Simulator PPCS, March 22, 2005

- SIMGL C1.4; Install and Test U1C31; November 2, 2007

- SIMGL C3.3; Simulator Certification Testing; September 21, 2005

- SCT 6.8.37.5; Stuck Open Condenser Dump Valve; August 29, 2006

- SCT 6.3.2; 75 Percent Power Heat Balance; July 12, 2006

- SCT 6.1.4; 100 Percent Steady State Drift Test; July 11, 2006

- SCT 6.8.13.3; Loss of a 4160 Volt Bus; December 7, 2006

- SCT 6.8.16.3; Generator Inadvertent Trip; July 18, 2006

- SCT 6.5.1; Manual Reactor Trip; April 3, 2006

- SCT 6.5.8; Loss of Coolant Accident With Loss of Offsite Power; March 30, 2006

- Simulator Review Committee Meeting Minutes; June 28, 2007

- Simulator Review Committee Meeting Minutes; February 12, 2007

- Simulator Work Orders Closed Out in Previous 12 Months; November 1, 2007

- List of Open Simulator SWOs; November 1, 2007

5

Attachment

- FP-T-SAT-80; Simulator Configuration Management; September 28, 2007

- FP-T-SAT-81; Simulator Testing and Documentation; September 28, 2007

- SIMGL C3.3; Simulator Certification Testing; September 21, 2005

- SIMGL C1.4; Simulator Modifications and Core Load Changes (Completed for Unit 1);

November 2, 2007

- ANSI/ANS-3.5-1985; Nuclear Power Plant Simulators for Use in Operator Training;

October 25, 1985

- Regulatory Guide 1.149; Nuclear Power Plant Simulation Facilities for Use in Operator License

Examinations; Revision 1; April 1987

- ANSI/ANS-3.4-1996; Medical Certification and Monitoring of Personnel Requiring Operator

Licenses for Nuclear Power Plants; February 7, 1996

- Regulatory Guide 1.134; Medical Evaluation of Licensed Personnel for Nuclear Power Plants;

Revision 3; March 1998

- Seven Licensed Operators Medical Records; dated various

- TRR 01116172; Review Two Exam Bank Questions for Difficulty Level Changes;

November 8, 2007

- TRR 01116174; Review Two JPMs for Difficulty Level; November 8, 2007

Procedures:

- FP-T-SAT-73; Licensed Operator Requalification Program Examinations; Revision 2

- JPM P000.042bAOT; Lineup for Transfer to Containment Sump Post-Accident Recirculation;

Revision 4

- SEG # PB-LOR-07E-001S; High Impact Session - PZR Pressure Transmitter RTS,

EH Malfunction and Containment Sump Recirculation; Revision 0

- EOP-1.3 Unit 1; Transfer to Containment Sump Recirculation - Low Head Injection;

Revision 39

- FL-LOR-TPD; NMC Fleet Licensed Operator Requalification Training Program Description;

Revision 0

- TRPR 33.0; Training Program Description; Licensed Operator Requalification Training

Program; Revision 25

- OM 3.10; Operations Personnel Assignments and Scheduling; Revision 23; August 9, 2007

- FP-T-SAT-71; NRC Examination Security Requirements; Revision 0

- CAP 01040650; Simulator PPCS Failed Completely, Affecting LOR As Found; July 20, 2006

- CAP 01073895; EP Issues from LOR 2006 Annual Operating Exams; January 25, 2007

- CAP 01092718; LOR Cycle 07C Schedule Affected by Simulator Malfunctions; May 15, 2007

- CAP 01111841; RWST Temp Found High OOS on Logs; September 18, 2007

- CAP 01113938; Operations Quarterly Status Report Accuracy Questioned; October 9, 2007

- CAP 01115710; Annual Operating Exam Security Lapse Results in Rework;

November 1, 2007

- NP 1.10.1; Record Keeping for NRC Licensed Operators; July 20, 2005

- OM 4.3.2; EOP/AOP Verification/Validation Process; Revision 15; October 29, 2007

CAPs/PCRs/TRRs Initiated for NRC-Identified Issues:

- CAP 01115978; Watchstander Restriction Form Not Filled Out Correctly; November 7, 2007

- CAP 01116144; PCRs Generated from CDBI Closed Out With No Action Taken;

November 8, 2007

- CAP 01116160; Simulator PPCS Problems During Exams; November 8, 2007

- PCR 01116095; Revise EOP 1.3 Unit 1; November 8, 2007

- PCR 01116097; Revise EOP 1.3 Unit 2; November 8, 2007

6

Attachment

1R13 Maintenance Risk Assessments and Emergent Work Control

- NP 10.3.6; Shutdown Safety Review and Safety Assessment; Revision 19

- Safety Monitor Calculation Reports for Units 1 and 2 for Applicable Work Weeks

- Work Week Execution Schedules for the Applicable Work Weeks

- Operator Logs for the Applicable Work Weeks

1R15 Operability Evaluations

Issue Reports:

- CAP 01111251; Discrepancy in CAF BHP Measured vs. Vendor Data; September 13, 2007

- OPR 154; Overload Concerns of Safeguards 480V AC Load Control and Motor Control

Centers; Revisions 1 Through 3

- OPR 157; EDG Operability Related to Electrical Loading During Certain Accident Scenarios;

Revision 3

- AR 01106938-01; Past Operability of P-32C; 10/25/2007

- CAP 01098680; P-32C SW Pump Vibration Nearing Acceptance Criteria Limit; June 24, 2007

- OPR 01098680; P-32C, Service Water Pump; Revision 0

- ACE 01098680-02; P-32C Vibration Issues; October 5, 2007

- CAP 01105929; P-32C SW Pump Fails IT-07C Testing; August 8, 2007

- CAP 01114171; OI 35C Requires Extensive Rewriting; October 11, 2007

- CAP 01119241; Concerns of PBNPs Use of IST Trend Data in OPRs; January 4, 2008

- CAP 01112660, 2P-29 Outboard Bearing Water Following IT-09A; September 24, 2007

- CAP 01113318, IT-09A Oil Analysis Results Not As Expected for 2P-29; September 27, 2007

- OPR1098358, Moisture Observed in Oil Sample From 2P-29 Outboard Bearing, Revision 2,

November 3, 2007

- OPR1098358, Moisture Observed in Oil Sample From 2P-29 Outboard Bearing, Revision 3,

November 4, 2007

- OPR1098358, Moisture Observed in Oil Sample From 2P-29 Outboard Bearing, Revision 4,

November 7, 2007

- OPR1098358, Moisture Observed in Oil Sample From 2P-29 Outboard Bearing, Revision 5,

November 10, 2007

Procedures:

- OI-35C; 480V Electrical Load Conservation; Revisions 3 and 4

- IT-07C; P-32C Service Water Pump (Quarterly); Revision 18

1R17 Permanent Plant Modifications

- Engineering Modification 05-006 and Engineering Changes EC1590 and 1591 Associated

With the Replacement of the EDG Heat Exchangers for EDGs G01 and G02

1R19 Post-Maintenance Testing

Procedures:

- RMP 9216-5;Service Water Pump Bowl Assembly Inspection and Maintenance; Revision 3

- IT 07E; P-32E Service Water Pump (Quarterly); Revision 19

- RMP 9387; AC Induction Motor MCE Testing Procedure; Revision 4

- IT-21; Charging Pumps and Valves Quarterly; Revision 18

- RMP 9003-1; Charging Pump Overhaul; Revision 6

7

Attachment

Work Orders:

- WO 302859-01; Service Water Pump Maintenance; October 24, 2007

- WO 300182-02; P-32E Service Water Pump Lower Than Expected Insul Resistance Reading;

October 24, 2007

- WO 219880; CVCS Charging Pump Modification - Pump 1P2B Renovation; Revision 0

1R22 Surveillance Testing

Procedures:

- IT-65; Containment Isolation Valves Quarterly; Revision 35

- PBTP 158; Leak rate Testing of 2SC-966C Containment Isolation Valve at Power; Revision 0

- IT-09A; Cold Start of the Turbine Driven Auxiliary Feedwater Pump Unit 2; Revision 45

- TS-81; Emergency Diesel Generator G01; Revision 75

- TS-82; Emergency Diesel Generator G02; Revision 76

1R23 Temporary Plant Modifications

Engineering Change:

- EC11633; Furmanite Injection of 2MS-232A MSR Valve

Work Orders:

- WO 340064; Furmanite Injection of 2MS-232A MSR Valve

- WO 346804; Furmanite Injection of 2MS-232A MSR Valve

2OS3 Radiation Monitoring Instrumentation and Protective Equipment

Issue Reports:

- Point Beach Nuclear Plant Radiation Monitoring System Health Report; December 6, 2007

- Snapshot Self-Assessment Report; SCBA Maintenance and User Training;

November 30, 2007

- Snapshot Self-Assessment Report; IP 71121.03 Inspection; November 30, 2007

- Snapshot Self-Assessment Report; 2006 INPO Area for Improvement - Radiation Monitoring

Instrument Program; November 23, 2007

- Radiation Protection Instrument Inventory and Calibration Due Date Report;

December 7, 2007

- Radcal Corporation Certificate of Conformance for Electrometer/Ion Chamber Model 20-X5-

1800 (SN 21707), Model 20X5-3 (SN 21548) and Model 20-X5-60 (SN 21344);

September 21, 2005

- Report of Calibration for the Canberra Fastscan Whole Body Count System at the Point Beach

Nuclear Plant; January 26, 2007

- Report of Evaluation of Isotopic Mixture and RP Programs; January 31, 2007

- Calibration Record for MGP Instrument Model AMP-100 (SN 474103); March 24, 2007

- Calibration Record for Eberline Instrument Model AMS-4 (SN A021); January 27, 2007

- Point Beach Emergency Plan Manual; EP 7.0 - Emergency Facilities and Equipment;

Revision 51

- Qualification Matrix and Training Status for Respiratory Protection; December 11, 2007

- Lesson Plan No. PB-SHE-004-SCRL; Respiratory Protection; Revision 1

- Scott Posicheck 3; Visual and Functional Test Records for Point Beach SCBA Units;

March 20, 2007

8

Attachment

Procedures:

- HPIP 7.52.4; PM-7 Personnel Monitor Checks; Revision 12

- HPIP 7.52.1; Personnel Contamination Monitor (PCM-1B/1C) Source Response Check;

Revision 13

- HPIP 5.66; Functional Check of the Gamma-60 Portal Monitor; Revision 21

- HPIP 2.1.1; Response Checks of Portable Survey Instruments; Revision 9

- HPIP 1.74; Operation of the Canberra Whole Body Counter; Revision 7

- HPCAL 3.2; Area Monitor Calibration Procedure DA1-1 and DA1-6 Detector Assemblies and

Associated Calibration Records for Unit 1 and Unit 2 Charging Pump Room (Low Range)

ARMs; December 19, 2006, and September 15, 2006

- HPCAL 3.3; Area Monitor Calibration Procedure DA1-4 and DA1-5 Detector Assemblies and

Associated Calibration Records for Unit 1 and Unit 2 Charging Pump Room (High Range)

ARMs; February 15, 2007, and February 12, 2007

- HPCAL 3.2 Calibration Record for Unit 1 and Unit 2 Seal Table ARMs; April 1, 2007, and

October 15, 2006

- HPCAL 3.2 Calibration Record for Unit 1 and Unit 2 Post Accident Sample Line Monitors;

August 13, 2007, and April 17, 2007

- HP CAL 3.2 Calibration Record for Safety Injection Pump Room Low Range and High Range

ARMs; September 18, 2006, and July 17, 2006

- 2ICP 13.017; Containment High Range Radiation Monitoring System Channels 2RE126,

2RE127, 2RE128 Calibration; December 12, 2006

- 1ICP 13.017; Containment High Range Radiation Monitoring System Channels 1RE126,

1RE127, 1RE-128 Calibration; March 14, 2007

- HPCAL 3.11; Containment High Range Detector Response Check Surveillance Record, Unit 1

Detectors (1RE126, 127 and 128), April 11, 2007; and Unit 2 Detectors (2RE126, 127 and

128), October 16, 2006

- HPCAL 1.10.2; Verification of J.L. Shepherd Model 89 Calibrator Dose Rates (Revision 1) and

Associated Output Verification for Calibrator No. 8269 and No. 8228; September 28, 2006

- HPCAL 1.1; Portable Survey Instrument Calibration, Repair and Response Checks;

Revision 18

- NMC Fleet Procedure FP-RP-ICC-01; Instrument Control and Calibration/Functional Testing

Frequencies of RP Instruments; Revision 3

- HPCAL 1.38; Calibration of the Portable Neutron Survey Instrument Analog Smart Portable

(ASP-1), and Associated Calibration Record (Instrument No. 9459); March 9, 2007

- HPCAL 2.8; Eberline PCM-1B Personnel Contamination Monitor Calibration Procedure and

Associated Calibration Record for Monitor No. 7737, October 17, 2007; No.7738,

March 30, 2007; and No. 7739, May 8, 2007

- HPCAL 2.8.1; Personnel Contamination Monitor Detector Efficiency Determination and

Associated Record for Monitor No. 7739; July 13, 2007

- HPCAL 2.11.1; Calibration of the Gamma-60 Portal Monitor and Associated Calibration

Record for Monitor No. 9485, March 12, 2007; and No. 9486, February 22, 2007

- HPCAL 2.21; Calibration of the Eberline Personnel Monitor PM-7 and Associated Calibration

Record for Monitor No. A112 (November 28, 2007); No. A113 (October 29, 2007); and

No. A114; (September 21, 2007)

- HPCAL 2.15; Small Articles Monitor Type SAM 9/11 Calibration and Efficiency and Associated

Calibration Record for Monitor No. 2; September 26, 2007

- PC 75 Part 1; Monthly and Turnaround Maintenance for the Scott Model 4.5 Self-Contained

Breathing Apparatus and Associated Surveillance Records for January 2006 through

December 2007

-

9

Attachment

- PBF-4077(c); Self-Contained Breathing Apparatus Inspection and Maintenance Records for

2006 and 2007

- HPIP 4.51.4; Scott Self-Contained Breathing Apparatus; Revision 8

Work Orders:

- CAP 01048997; Compliance with Fleet Procedure; September 8, 2006

- CAP 01080787; Gamma-60 Source Check Concerns; March 6, 2007

- CAP 00906738; RP Survey Instrument Response Checks and Instrument Sign-Out;

February 7, 2006

- CAP 01081898; Failure of Meter Movement for C-59 Area Monitor RE-111; March 13, 2007

- CAP 01091161; Lack of Bases for RP Equipment Functional Check; May 5, 2007

- CAP 01087730; Possible Trend With Poor Teletector Performance; April 14, 2007

4OA1 Performance Indicator Verification

Issue Reports:

- Monthly Data Elements for RETS/ODCM Radiological Effluents; December 2006 -

November 2007

- Liquid and Gaseous Effluent Summary Data and Dose Calculation Results; March 2007

4OA2 Problem Identification and Resolution

Procedures:

- NP 2.1.4 Operator Burdens; Revision 7

4OA3 Followup of Events and Notices of Enforcement Discretion

Issue Reports:

- CAP 01111841; RWST Temp Found High OOS on Logs; September 18, 2007

- RCE 01111841-01; Unit 2 Refueling Water Storage Tank Temperature High Resulting in

Unplanned TSAC; Revision 1

- RCE 01090456-01; 1P-29 Turbine Driven Auxiliary Feedwater Pump Outboard Bearing Issues

4OA5 Other Activities

Documents:

- EPRI Terry Turbine Guide; Terry Turbine Maintenance Guide, AFW Application TR-1007461

- VTM 0004 Manual: Terry Steam Turbine Company; Auxiliary Feedwater Pump Turbine Drive;

Revision 30

- Technical Data Sheet; Loctite High Temp Red

- Technical Data Sheet; Turbo 50

- Technical Data Sheet; Temp Tite II String Kit

- RCE 01090456-01; IP-29 Turbine Driven Auxiliary Feedwater Pump Outboard Turbine Bearing

Issues

- MPR Report; Point Beach Nuclear Station; Water Containment of AFW Turbine Lube Oil

- Memo on OST Device Drain Plug - Justification of Drain Plug Removal

- Station Logs - From Present Back to June 21, 2007; Focus on Auxiliary Feed Runs

- OCC Logs - November 2006 Outage, September 2007 Overhaul, and November 2007

Overhaul

- 2P-29 Event Folders

- Applicable Oil Analysis Results Record

10

Attachment

- RCE 96-08; Unit 1 Reactor Taken Critical with Both 1P-29 Turbine-Driven Auxiliary Feedwater

Pump Discharge Motor-Operated Valves (1AF-4000, 1AF-4001) Found Shut

- RCE 98-150; Unit 1 Turbine-Driven Auxiliary Feed Pump Turbine Maintenance Rework

- RCE 01115748; 2P-29 AFW Pump Moisture in Oil

Procedures:

- RMP 9044-1; Auxiliary Feedwater Pump Terry Turbine Overhaul

- IT-09A; Cold Start of Turbine-Driven Auxiliary Feed Pump and Valve Test

- OI-62B; Turbine-Driven Auxiliary Feedwater System

Condition Reports and Work Orders:

- CAP 01049806; 1P-29 AFW Pump S/D Due to Low Oil Level in Bubbler; September 12, 2006

- CAP 01051133; Oil Level Problems Encountered During PMT for 1P-29 AFP;

September 19, 2006

- CAP 01062958; Reinstallation of Insulation for 2P-29 TDAFW Pump not Done;

November 20, 2006

- CAP 01068606; 1P-29 Aux Feed Pump Suction Sodium Lab Analysis was High;

December 20, 2006

- CAP 01086108; Additional Paint Removal Required - Not correctly Identified; April 5, 2007

- CAP 01097185; Differences Noted Between RMP 9044-1 and EPRI Guide; June 17, 2007

- CAP 01097732; Improvement Recommendations for RMP 9044-1; June 20, 2007

- CAP 01097736; Declining Trend in 2P-29 TDAFW Pump Speed Noted; June 20, 2007

- CAP 01098358; Moisture Observed in Oil Sample from 2P-29 Turbine Reservoir;

June 21, 2007

- CAP 01098364; AFW Steam Pipe Supports Lubra-Plates Have Been Painted; June 22, 2007

- CAP 01098445; Benchmark in Service Testing of Aux Feed Systems; June 22, 2007

- CAP 01098525; Unit 1 and 2 TDAFW Pump Oil Sampling; June 22, 2007

- CAP 01098536; No Specific Training for Turbine Driven AFPs; June 22, 2007

- CAP 01098615; U2R28 P-29-T: GL 89-13 HX PM Not Properly Documented; June 22, 2007

- CAP 01098626; AFW Casing Sealant Review; June 23, 2007

- CAP 01098633; 1P-29 TDAFW Pump Sentinel Valve Opened on Start; June 23, 2007

- CAP 01099142; Unable to Analyze Water Content of Oil Sample; June 26, 2007

- CAP 01099272; Oil Sample for 2P-29-T May Not Have Been Taken Correctly; June 26, 2007

- CAP 01099402; 2007 AFW Inspection - Review of Additional Engineer Programs;

June 27, 2007

- CAP 01099576; 2P-29 TDAFWP Oil Sample High Water Content; June 28, 2007

- CAP 01099876; Water Content Analysis Results for 2P-29-T OB Bearing; June 29, 2007

- CAP 01100698; IT-08A/IT-09A Do Not Contain 1996 Reg Commitments; July 7, 2007

- CAP 01100865; 1P-29-T Coupling Stretch Not Verified After Re-alignment; July 9, 2007

- CAP 01100874; RMP 9044-1 Contains Vague Guidance for Thomas Coupling Setting;

July 9, 2007

- CAP 01101114; Potential Preconditioning of 1(2)P-29 TDAFW Pump; July 11, 2007

- CAP 01101562; 2P-29 Oil Sample Put on HOLD by Supply Chain Buyer; July 12, 2007

- CAP 01102282; 1P-29 Terry AFP Thomas Coupling Setting Concerns; July 18, 2007

- CAP 01102417; RMP 9044-1, Revision 12, Provides Incorrect Acceptance Criteria;

July 19, 2007

- CAP 01102492; Quarantine Oil Samples Taken from 2P-29-T Under WO 335172;

July 19, 2007

- CAP 01102642; 2P-029-T Oil Dripping from Outboard Bearing Housing Seal; July 19, 2007

- CAP 01102655; Water Still Indicated in Oil from 2P-29-T OB BRG; July 20, 2007

11

Attachment

- CAP 01102868; Higher Than Expected Water in 2P-29-T OB BRG Post Run Sample;

July 21, 2007

- CAP 01102875; 2P-29 Appendix R Functionality; July 21, 2007

- CAP 01102902; Documentation of Observation, 2P-29-T Temperature Indication;

July 22, 2007

- CAP 01102903; Verified Steam Leak at Seal on 2P-29-T OB Bearing; July 22, 2007

- CAP 01103469; Form for Bearing Stabilization on 1P-29 and 2P-29 Is Not Formalized;

July 25, 2007

- CAP 01103520; Potential Improper Oil Issued for 2P-29 Aux Feed Pump; July 25, 2007

- CAP 01103623; Question Concerning Bearing Coolers on P-029 Turbines; July 26, 2007

- CAP 01103841; 1P-29T and 2P-29T OB Steam Gland Drain Lined Pitch Is Incorrect;

July 27, 2007

- CAP 01106373; Evaluate Use of New Governor Drive Coupling on P-29T; August 10, 2007

- CAP 01107473; Oil Storage Requirements Questioned; August 17, 2007

- CAP 01108275; AFP Bearings Failed Vendor Dimensional Inspection; August 23, 2007

- CAP 01108351; 2P-29-T Outboard Bearing Aluminum Fill Plug; August 23, 2007

- CAP 01108355; 1P-29-T Oil Analysis Results Indicated As Alarm; August 23, 2007

- CAP 01108426; 2P-29-T Governor Oil Level High; August 23, 2007

- CAP 01108429; Unexpected Oil Leak Rate While Running 2P-29-T; August 23, 2007

- CAP 01108576; FPL AFW System Focused Assessment - Operations Observations;

August 24, 2007

- CAP 01109045; Oil Analysis Results Questioned; August 28, 2007

- CAP 01109571; P-29-T Inbound Bearing Oiler Upper Casting Slightly Damaged;

August 31, 2007

- CAP 01109572; 2P-29-T Oiler Height Settings; August 31, 2007

- CAP 01112474; 2P-29 Pump Outboard Packing Has Excessive Leakage; September 21, 2007

- CAP 01112475; 2P-29 Outboard Turbine Bearing High Temp Alarm During IT-9A;

September 21, 2007

- CAP 01112533; 2P-29-T Changing Oil and Stabilization; September 21, 2007

- CAP 01112567; Terry Turbine Gland Case leak Off Lines Not Optimal; September 22, 2007

- CAP 01112579; Wrong Revision of Procedure Used for 2P-29-T Work; September 22, 2007

- CAP 01112587; 2P-29-T TDAF Wheel Lap Measurement; September 22, 2007

- CAP 01112596; September 21, 2007 2P-29 Oil Analysis Results; September 22, 2007

- CAP 01112597; 2P-29-T Outboard Terry Turbine Bearing; September 22, 2007

- CAP 01112609; 2P-29-T Outboard BRG Thermocouple Damaged During BRG Crush;

September 23, 2007

- CAP 01112626; 2P-29-T Outboard Bearing Oil Ring Contacting Oil Cooler;

September 23, 2007

- CAP 01112631; 2P-29-T Terry Turbine Casing Bolts; September 23, 2007

- CAP 01112641; RMP 9044-1 Did Not Have Correct torque Value; September 23, 2007

- CAP 01112660; 2P-29-T OB BRG Water Following IT-09A; September 24, 2007

- CAP 01113029; RMP 9044-1 Wrong Revision Used for 2P-29-T Work; September 25, 2007

- CAP 01113318; IT-09A Oil Analysis Results Not As Expected for 2P-29-T;

September 27, 2007

- CAP 01113438; P-29-T Oil Cooler Differences Outboard End; October 1, 2007

- CAP 01113972; IT-290B and IT-295B Makes Reference to Replaced ERPI Guide;

October 10, 2007

- CAP 01113973; Differences Between EPRI Guide and IT-08A, B and IT-09A,B;

October 10, 2007

- CAP 01113978; EPRI Terry Turbine Manual Recommendation for AF; October 10, 2007

- CAP 01115697; 2P-29 TDAFP Inbound Pump Bearing Oil Leak; November 1, 2007

12

Attachment

- CAP 01115748; 2P-29 Moisture in Oil Concern; November 1, 2007

- CAP 01115768; Visual Indications Post IR-09A on November 2, 2007 for Oil;

November 2, 2007

- CAP 01115778; Oil Sampling Concerns for 2P-29 AFW Pump; November 2, 2007

- CAP 01115808; Oil Analysis Results for 2P-29-T on November 3, 2007; November 3, 2007

- CAP 01115810; 2P-29 Returned to OPS in an Operable But Degraded Condition;

November 3, 2007

- CAP 01115819; November 2, 2007 Log Entry for 2P-29 Availability Incomplete;

November 4, 2007

- CAP 01115832; Appears Samples Not Taken Per Request; November 5, 2007

- CAP 01115952; Oil Analysis Results for 2P-29-T from November 5, 2007; November 6, 2007

- CAP 01116158; 2P-29 Governor Gear Drive Oil Color; November 8, 2007

- WO 219237; Uncouple 2P-29 Per Callup Text; March 8, 2006

- WO 219238; Inspect Inboard and Outboard Bearing; March 8, 2006

- WO 219239; Emergency Governor Inspection; March 8, 2006

- WO 219240; Sample Oil in 2P-29 Turbine Governor; March 8, 2006

- WO 219448; Perform Overhaul; October 24, 2006

- WO 267802; ten-Year Overhaul; November 12, 2006

- WO 268232; Sample Oil in 2P-29 Turbine Governor; November 12, 2006

- WO 268233; GL 89-13 - Inspect Bearing Oil Coolers; November 12, 2006

- WO 268234; Emergency Governor Inspection; November 12, 2006

- WO 268235; Uncouple 2P-29 Pump from Its Turbine; November 12, 2006

- WO 334308 Auxiliary Feedwater Pump Terry Turbine Overhaul; September 12, 2007

- WO 334597; Sample and Change Oil as Required; November 9, 2007

- WO 335167; Sample and Change Oil As Required; June 28, 2007

- WO 346758; Auxiliary Feedwater Pump Terry Turbine Overhaul; November 2, 2007

NRC-Identified Condition Reports

- AR 01100068; Closeout Based on Incorrect Info

- AR 01100293; Benchmarking/Snapshot Evaluation for VTI

- AR 01100509; Potential HU Crosscut

- AR 01100985; Cable ZA1327FA Not Included in App

- AR 01101029; Error Noted on Drawing WEST 499B466

- AR 01101383; Near Miss During ILT NRC Exam

- AR 01101421; Untimely Corrective Actions

- AR 01101444; Compliance With Appendix R,Section III

- AR 01101461; Potential Coincident Fire Induced Failure

- AR 01101506; NFPA 13 Issues With G-01 and G-02 R

- AR 01101596; Procedure EOP-3 Change Needed for Bistable Tube Rupture

- AR 01101667; Inconsistent/Inadequate Direction

- AR 01101704; Procedure EOP-3 Steps Out of Sequence

- AR 01102113; Scaffold Clearance Questioned

- AR 01102590; Incorrect Description of Pushbutton

- AR 01103769; Error in Calculation S-11165-035-SW

- AR 01105181; Fire Extinguishers Removed for Annu

- AR 01105290; Inappropriate Screened AR 11033415

- AR 01105804; PI Indicator Does Not Match INPO CD

- AR 01105948; PI-2849 Discharge Pressure on E SW

- AR 01105993; Quench Curve Check Performed

- AR 01106042; Fluctuations Seen on P-32E SW Pump

13

Attachment

- AR 01106118; Façade Groundwater Samples Not Shipped

- AR 01107098; Missing Bolts on Subsoil Drainage

- AR 01107355; Stalling of MOVs while Load Sequencing

- AR 01107452; Lube oil Tank Rupture

- AR 01107461; NRC RP Inspection: Groundwater

- AR 01107485; Weakness Identified in 10 CFR 50.75(g)

- AR 01107520; Debris in Subsoil Drainage System

- AR 01107630; Create Engineering Documents for Flooding

- AR 01107634; Formally Verify Function and Capacity

- AR 01108334; Radiodine Results High - Evaluate

- AR 01108724; Supplement Needed for LAR 249

- AR 01109665; LAR 247 submittal Being Withdrawn

- AR 01109968; 2007 Mid-Cycle Performance Review

- AR 01109992; 2007 EP Drill

- AR 01111043; LER 2007-003 Related AR Severity

- AR 01111296; RCE-01075472 Not Revised per PARB

- AR 01112896; Improvements in Posting and Access

- AR 01112924; Postings in RCA Yard Found Faded

- AR 01112934; Cleanliness in the Drumming Room

- AR 01112981; Point Beach Nuclear Plant Flood Watch Commitment Information

- AR 01113207; NRC Radwaste Inspection/ATCOR Equip

- AR 01113226; NRC Question on 10 CFR 20, Appendix G, A.3

- AR 01113277; Material Condition

- AR 01113347; NRC Radwaste Inspection Request

- AR 01113420; NRC Inspection Debrief

- AR 01113508; Security Documentation Enhancement

- AR 01113563; Security Weapons Documentation

- AR 01114426; Procedure Noncompliance of NP 8.4.1

- AR 01114599; PC 99 May Need To Be Implemented

- AR 01114637; Material in Yard

- AR 01114731; Loose Materials Found in the Protected Area

- AR 01115102; Weakness Identified in Crew Information

- AR 01115108; Unit 2 MFRV Turnover Less Than Complete

- AR 01115189; Scaffold Material in Contact

- AR 01115311; Small Coolant Leak on G-04 EDG

- AR 01115486; Point Beach Nuclear Plant Use of Maintenance Run

- AR 01115556; Requirements of NP 7.7.5 for Maintenance

- AR 01115620; Error Found by Review of Maintenance

- AR 01115703; OPR 01114308 Requires Revision

- AR 01115713; Number of Maintenance Rule Functional Failures

- AR 01115729; Documentation of D-06 Performance

- AR 01115818; Potential SSD Equipment Missing From Documentation

- AR 01115819; November 2, 2007 Log Entry for 2P-29

- AR 01115820; LAR 256, ILRT Interval Extension

- AR 01115838; Revision 3 Required for OPR 1098358

- AR 01115876; EPRI Guidance Not Included in RMP 9

- AR 01115881; Wording in OPR 1098358 May Be Misleading

- AR 01115951; Unit 2 TDAFWP Event - NRC Question

- AR 01115978; Watchstander Restriction Form Not Filed

- AR 01116011; 2P-29 Oil Samples

- AR 01116150; Discrepancy in TAN Values

14

Attachment

- AR 01116158; 2P-29 Governor Gear Drive Oil Color

- AR 01116250; Lack of Sample Splitting Procedure

- AR 01116334; Minor Shaft Pitting - 2P-29

- AR 01116442; 2P-029-T Oil Dregs

- AR 01116533; LAR 256 ILRT Extension Request

- AR 01116589; MSPI Records Missing From EDMS

- AR 01116594; HPIT - Confirmation Bias in Engineering

- AR 01116619; 2P-29-T - OPR Testing Methodology

- AR 01116647; Procedural Temporary Change Chart

- AR 01116658; General Observations Regarding 2P-0

- AR 01116673; Clarification Needed for Sealant

- AR 01116688; Review/Revise OPR 1098358

- AR 01116794; Minor Error Found in CDE

- AR 01116819; Unavailability Guidance for MR and NEI

- AR 01117062; 1RMP-9096 and SLP 2 Revisions Required

- AR 01117126; Revise/Correct EOP Setpoint for L.25 and L.4

- AR 01117152; Revise IP-29 Root Cause to Address Issue

- AR 01117163; MI 32.9 Scaffold Stabilization Criteria

- AR 01117170; Rubber Pads Not Installed on RCP

- AR 01117200; NRC Noted Service Water Drawing - Verification Temperature Indicator

- AR 01117205; NRC Noted Auxiliary Feedwater Drawing

- AR 01117350; IT 40/45 Do Not Contain Caution Statements

- AR 01117459; Façade Wells - H-3 in Ground Water

- AR 01117637; Errors in Calculations - PCI-5344-S02

- AR 01117860; Provide Preliminary Technical Basis - Temporary Storage Items

- AR 01118002; Errors in Calculations - PCI-5344-S01

- AR 01118105; ACE 10434692 - Actions Not Identified

- AR 01118106; PM-7 Functional Check Periodicity

- AR 01118107; H3 Sample Results

- AR 01118141; License Amendment Quality/Timeliness

- AR 01118144; Errors in Structural Calculation

- AR 01118148; Rigging Evaluation Documentation

- AR 01118185; Evaluate Load Handling Procedure

- AR 01118189; NRC BL 2007-01, Security Officer

- AR 01118194; Recommended Improvement to DG-M10

- AR 01118195; SCBA LP Does Not Show How to Change

- AR 01118200; Support Model in Calculation PBNP-9

- AR 01118202; Low Design Margin for Plant Component

- AR 01118207; SCBA Monthly Location Inspection

- AR 01118213; Consider Completing and Audit on SC

- AR 01118259; NRC Inspection Observation

- AR 01118722; NRC Concern About Secondary Sample

- AR 01118844; Clarification Regarding Operability - Implement Recommendations

- AR 01118847; NRC Submittal Rejected

15

Attachment

LIST OF ACRONYMS USED

AC

Alternating Current

ACE

Apparent Cause Evaluation

AFW

Auxiliary Feedwater

AOP

Abnormal Operating Procedure

ARM

Area Radiation Monitor

ASME

American Society of Mechanical Engineers

CAP

Corrective Action Program Document (Condition Report)

CEDE

Committed Effective Dose Equivalent

CFR

Code of Federal Regulations

CoC

Certificate of Compliance

DRP

Division of Reactor Projects

DRS

Division of Reactor Safety

EDG

Emergency Diesel Generator

EOP

Emergency Operating Procedure

EPRI

Electric Power Research Institute

FSAR

Final Safety Analysis Report

IEEE

Institute of Electrical & Electronic Engineers

IMC

Inspection Manual Chapter

IP

Inspection Procedure

ips

Inches Per Second

IR

Inspection Report

ISI

Inservice Inspection

IST

Inservice Test

IV

Independent Verification

JPM

Job Performance Measure

kV

Kilovolt

kW

Kilowatt

LCO

Limiting Condition for Operation

LER

Licensee Event Report

LHRA

Locked High Radiation Area

LOCA

Loss of Coolant Accident

LOOP

Loss of Off-site Power

LORT

Licensed Operator Requalification Training

MG

Motor-Generator

MOV

Motor-Operated Valve

mrem

Millirem

MSPI

Mitigating Systems Performance Index

NCV

Non-Cited Violation

NEI

Nuclear Energy Institute

NIOSH

National Institute of Safety & Health

NMC

Nuclear Management Corporation

NRC

U.S. Nuclear Regulatory Commission

ODCM

Offsite Dose Calculation Manual

OM

Operational Maintenance

OPR

Operability Evaluation

OWA

Operator Workaround

PI

Performance Indicator

PI&R

Problem Identification and Resolution

PM

Planned or Preventative Maintenance

16

Attachment

PMT

Post-Maintenance Testing

ppm

Parts Per Million

PRA

Probabilistic Risk Assessment

QA

Quality Assurance

RCA

Radiologically Controlled Area

RCE

Root Cause Evaluation

RETS

Radiological Effluent Technical Specification

RHR

Residual Heat Removal

RP

Radiation Protection

RPS

Reactor Protection System

RPV

Reactor Pressure Vessel

RWST

Refueling Water Storage Tank

SAT

Systems Approach to Training

SCBA

Self-Contained Breathing Apparatus

SDP

Significance Determination Process

SSC

Structure, System, or Component

SW

Service Water

TDAFW

Turbine-Driven Auxiliary Feedwater

TS

Technical Specification

URI

Unresolved Item

WO

Work Order

VIO

Violation