Text

IR 05000445-07-002, 05000446-07-002; 01/01/2007-03/23/2007; Comanche Peak Steam Electric Station, Units 1 and 2; Surveillance Testing
	ML071271010
Person / Time
Site:	Comanche Peak
Issue date:	05/04/2007
From:	Clay Johnson; NRC/RGN-IV/DRP/RPB-A
To:	Blevins M; TXU Power
References
	Download: ML071271010 (33)
	v • d • e

May 4, 2007

Mike Blevins, Senior Vice President

and Chief Nuclear Officer

TXU Power

ATTN: Regulatory Affairs

Comanche Peak Steam Electric Station

P.O. Box 1002

Glen Rose, TX 76043

SUBJECT: COMANCHE PEAK STEAM ELECTRIC STATION - NRC INTEGRATED

INSPECTION REPORT 05000445/2007002 AND 05000446/2007002

Dear Mr. Blevins:

On March 23, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection

at your Comanche Peak Steam Electric Station, Units 1 and 2, facility. The enclosed integrated

inspection report documents the inspection findings which were discussed on March 29, 2007,

with Mr. M. Lucas and other members of your staff.

This inspection examined activities conducted under your licenses as they related to safety and

compliance with the Commission's rules and regulations and with the conditions of your

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

interviewed personnel.

The report documents one NRC identified finding of very low safety significance (Green). The

finding was determined to involve a violation of NRC requirements. However, because of the

very low safety significance and because it was entered into your corrective action program, the

NRC is treating the finding as a noncited violation (NCV) consistent with Section VI.A.1 of the

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 200555-

0001; with copies to the Regional Administrator, Region IV, 611 Ryan Plaza Drive, Suite 400,

Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory

Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Comanche

Peak Steam Electric Station.

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 made available electronically for public inspection

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

of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at

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

TXU Power -2-

Should you have any questions concerning this inspection, we will be pleased to discuss them

with you.

Sincerely,

/RA/

Claude E. Johnson, Chief

Project Branch A

Division of Reactor Projects

Dockets: 50-445

50-446

Licenses: NPF-87

NPF-89

Enclosure:

NRC Inspection Report 05000445/2007002

and 05000446/2007002 w/attachment:

Supplemental Information

cc w/Enclosure:

Fred W. Madden, Director

Regulatory Affairs

TXU Power

P.O. Box 1002

Glen Rose, TX 76043

George L. Edgar, Esq.

Morgan Lewis

1111 Pennsylvania Avenue, NW

Washington, DC 20004

Terry Parks, Chief Inspector

Texas Department of Licensing

and Regulation

Boiler Program

P.O. Box 12157

Austin, TX 78711

The Honorable Walter Maynard

Somervell County Judge

P.O. Box 851

Glen Rose, TX 76043

TXU Power -3-

Richard A. Ratliff, Chief

Bureau of Radiation Control

Texas Department of Health

1100 West 49th Street

Austin, TX 78756-3189

Environmental and Natural

Resources Policy Director

Office of the Governor

P.O. Box 12428

Austin, TX 78711-3189

Brian Almon

Public Utility Commission

William B. Travis Building

P.O. Box 13326

Austin, TX 78711-3326

Susan M. Jablonski

Office of Permitting, Remediation

and Registration

Texas Commission on

Environmental Quality

MC-122

P.O. Box 13087

Austin, TX 78711-3087

TXU Power -4-

Electronic distribution by RIV:

Regional Administrator (BSM1)

DRP Director (ATH)

DRS Director (DDC)

DRS Deputy Director (RJC1)

Senior Resident Inspector (DBA)

Branch Chief, DRP/A (CEJ1)

Senior Project Engineer, DRP/A (TRF)

Team Leader, DRP/TSS (FLB2)

RITS Coordinator (MSH3)

DRS STA (DAP)

D. Cullison, OEDO RIV Coordinator (DGC)

ROPreports

CP Site Secretary (ESS)

SUNSI Review Completed: _CEJ__ ADAMS: / Yes G No Initials: ___CEJ____

/ Publicly Available G Non-Publicly Available G Sensitive / Non-Sensitive

R:\_REACTORS\_CPSES\2007\CP2007-02 DBA.wpd

RIV:RI:DRP/A SPE:DRP/A SRI:DRP/A C:DRS/EB1 C:DRS/OB

AASanchez;mjs TRFarnholtz DBAllen WBJones ATGody

T-TRF /RA/ T-TRF CPaulk For TOM for

4/30/07 4/25/07 4/30/07 4/24/07 4/25/07

C:DRS/PSB C:DRS/EB2 C:DRP/A

MPShannon LJSmith CEJohnson

/RA/ /RA/ /RA/

4/27/07 4/22/07 5/4/07

OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Dockets: 50-445, 50-446

Licenses: NPF-87, NPF-89

Report: 05000445/2007002 and 05000446/2007002

Licensee: TXU Generation Company LP

Facility: Comanche Peak Steam Electric Station, Units 1 and 2

Location: FM-56, Glen Rose, Texas

Dates: January 1 through March 23, 2007

Inspectors: D. Allen, Senior Resident Inspector

A. Sanchez, Resident Inspector

T. McKernon, Senior Operations Engineer

J. Drake, Operations Engineer

K. Clayton, Operations Engineer

P. Elkmann, Emergency Preparedness Inspector

R. Kopriva, Senior Reactor Inspector, Engineering Branch 1

W. Sifre, Senior Reactor Inspector, Engineering Branch 1

R. Azua, Reactor Inspector, Engineering Branch 1

G. George, Reactor Inspector, Engineering Branch

Approved by: Claude Johnson, Chief, Project Branch A

Division of Reactor Projects

-1- Enclosure

SUMMARY OF FINDINGS

IR 05000445/2007002, 05000446/2007002; 01/01/2007-03/23/2007; Comanche Peak Steam

Electric Station, Units 1 and 2; Surveillance Testing.

This report covered a 3-month period of inspection by two resident inspectors, three Operations

Engineers, four Engineering Branch Inspectors, and an Emergency Preparedness Inspector.

One Green noncited violation was identified. The significance of most findings is indicated by

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

Determination Process. Findings for which the significance determination process does not

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

NRC's program for overseeing the safe operation of commercial nuclear power reactors is

described in NUREG-1649, ?Reactor Oversight Process, Revision 3, dated July 2000.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green. An NRC identified noncited violation of Technical Specification 5.4.1.e was

identified for the failure to establish, implement and maintain written procedures for the

inservice testing program. STA-711, Inservice Testing Program for Pumps and Valves

required a new set of reference values be determined following pump replacement and

all subsequent test results be compared to the new reference values. Station Service

Water Pump 2-02 was declared operable on October 19, 2006, following pump

replacement and, although the new pumps performance was fully acceptable, the

inservice testing requirements to establish new reference values were not performed

and subsequent test results were not compared to the new reference values. On

March 13, 2007, the licensee provided technical justification for the operability of Station

Service Water Pump 2-02, based, in part, on comparison of the new pump performance

with the design flow requirements.

This violation is more than minor because it resulted in a condition where there was a

reasonable doubt of the operability of the pump, and programmatic deficiencies were

identified in the Inservice Testing Program that could lead to significant errors if not

corrected. The violation affected the mitigation system cornerstone objective to ensure

the capability of the station service water system and the attribute of human

performance. The finding has very low safety significance because the pump was

always fully capable of performing its safety function. The cause of the finding has a

crosscutting aspect in the area of human performance with a resources component, in

that, the licensee failed to ensure complete, accurate and up-to-date procedures were

available and adequate to implement the inservice testing program (Section 1R22).

B. Licensee Identified Violations

None.

-2- Enclosure

REPORT DETAILS

Summary of Plant Status

Comanche Peak Steam Electric Station (CPSES), Unit 1 began the reporting period at

100 percent power. The unit began power coastdown on February 17, 2007, and commenced

a reactor shutdown on February 24, 2007, at 10:00 a.m. to begin refueling outage 1RF12. The

reactor was manually tripped and the unit entered Mode 3 at 12:00 noon that same day. The

unit remained in the outage through the remainder of the reporting period.

CPSES Unit 2 operated at essentially 100 percent power for the entire reporting period.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

a. Inspection Scope

The inspectors reviewed Abnormal Condition Procedure (ABN) ABN-912, Cold Weather

Preparations/Heat Tracing and Freeze Protection System Malfunction, Revision 7,

Section 2, Cold Weather Preparations, in the Unit 1 control room in anticipation of

colder weather conditions. The inspectors reviewed the Procedure ABN-912

attachments and control room log to verify that plant cooling units and dampers had

been aligned for cold weather and that temperatures were being monitored in

accordance with the attachments. On March 2, 2007, the inspectors walked down

Units 1 and 2 emergency diesel generators (EDGs) and the common control room

heating, ventilation, and air conditioning system for overall readiness for expected cold

weather.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R02 Evaluations of Changes, Tests, or Experiments (71111.02)

a. Inspection Scope

The inspectors reviewed the effectiveness of the licensees implementation of changes

to the facility structures, systems, and components (SSC); risk-significant normal and

emergency operating procedures; test programs; and the updated final safety analysis

report in accordance with 10 CFR 50.59, "Changes, Tests, and Experiments." The

inspectors utilized Inspection Procedure 71111.02, "Evaluation of Changes, Tests, or

Experiments," for this inspection.

-3- Enclosure

The inspectors reviewed six safety evaluations performed by the licensee since the last

NRC inspection of this area at CPSES. The evaluations were reviewed to verify that

licensee personnel had appropriately considered the conditions under which the

licensee may make changes to the facility or procedures or conduct tests or

experiments without prior NRC approval. The inspectors reviewed three

licensee-performed applicability determinations and 15 screenings, in which licensee

personnel determined that evaluations were not required, to ensure that the exclusion of

a full evaluation was consistent with the requirements of 10 CFR 50.59. Evaluations,

screenings, and applicability determinations reviewed are listed in the attachment to this

report.

The inspectors reviewed and evaluated a sample of recent licensee condition reports to

determine whether the licensee had identified problems related to 50.59 evaluations,

entered them into the corrective action program, and resolved technical concerns and

regulatory requirements. The reviewed condition reports (SMART FORMS) are

identified in the Attachment.

The inspection procedure specifies that the inspectors review a minimum sample of

six licensee safety evaluations and 12 applicability determinations and screenings

(combined). The inspectors completed a review of six licensee safety evaluations and a

combination of 18 applicability determinations and screenings.

Additional samples of Inspection Procedure 71111.02 Evaluations of Changes, Tests,

or Experiments will be located in NRC Inspection Report 05000445/2007006 covering

the 10 CFR 50.59 reviews performed for the Steam Generator and Reactor Vessel

Head Replacement Project.

b. Findings

No findings of significance were identified

1R04 Equipment Alignment (71111.04)

.1 Partial System Walkdown (71111.04)

a. Inspection Scope

The inspectors: (1) walked down portions of the below listed risk important systems and

reviewed plant procedures and documents to verify that critical portions of the selected

systems were correctly aligned; and (2) compared deficiencies identified during the

walkdown to the licensee's corrective action program to ensure problems were being

identified and corrected.

Unit 1 Train B containment spray system in accordance with System Operating

Procedure (SOP) SOP-204A, Containment Spray System, Revision 14, and

-4- Enclosure

Operations Testing Procedure (OPT) OPT-205A, "Containment Spray System,"

Revision 16, while the Train A containment spray system was inoperable for

scheduled surveillance, on January 29, 2007

Unit 2 Train B centrifugal charging system while Train A was out-of-service for

maintenance, in accordance with SOP-103B, Chemical and Volume Control

System, Revision 11, on January 30, 2007

Unit 2 Train A safety injection system while Train B was out-of-service for

maintenance, in accordance with SOP-201B, Safety Injection System,

Revision 6, on February 13, 2007

Unit 1 Train A station service water (SSW) system in accordance with SOP-

501A, Station Service Water System, Revision 16, and OPT-207A, "Service

Water System," Revision 13, after realignment from the Train A outage during

1RF12, on March 20, 2007

The inspectors completed four samples.

b. Findings

No findings of significance were identified.

.2 Detailed Semiannual System Walkdown (71111.04S)

a. Inspection Scope

The inspectors conducted a detailed inspection of the spent fuel pool cooling system to

verify the functional capability of the system as described in the design basis

documents. During the walkdowns, inspectors examined system components for

correct alignment, for electrical power availability, and for material conditions of

structural components that could degrade system performance. In addition, the

inspectors referenced and used the following documents to verify proper system

alignment and setpoints:

C Design Basis Document (DBD) DBD-ME-235, Spent Fuel Pool Cooling and

Cleanup System, Revision 15

C SOP-506, Spent Fuel Pool Cooling and Cleanup System, Revision 17

C CPSES Drawing M1-0235, Flow Diagram Spent Fuel Pool Cooling and

Cleanup System, Revision CP-19 and 21

The inspectors also reviewed recent corrective action documents, system health

reports, outstanding work requests, and design issues to determine if any of

these items could effect the systems ability to perform as designed. The

-5- Enclosure

inspectors interviewed appropriate plant staff regarding the system's

maintenance history. A field walkdown was completed during the weeks of

March 5 and 19, 2007.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05Q)

Fire Area Tours

a. Inspection Scope

The inspectors walked down the listed plant areas to assess the material condition of

active and passive fire protection features and their operational lineup and readiness.

The inspectors: (1) verified that transient combustibles and hot work activities were

controlled in accordance with plant procedures; (2) observed the condition of fire

detection devices to verify they remained functional; (3) observed fire suppression

systems to verify they remained functional; (4) verified that fire extinguishers and hose

stations were provided at their designated locations and that they were in a satisfactory

condition; (5) verified that passive fire protection features (electrical raceway barriers,

fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems)

were in a satisfactory material condition; (6) verified that adequate compensatory

measures were established for degraded or inoperable fire protection features; and

(7) reviewed the corrective action program to determine if the licensee identified and

corrected fire protection problems.

Fire Zone AA21D - Units 1 and 2 Auxiliary Building Elevation 831' on

February 10, 2007

Fire Zone 1SA - Unit 1 Train B emergency core cooling systems (ECCS)

equipment rooms Elevations 773', 790', 810', and 831' on February 10, 2007

Fire Zone AA 153/154 - Units 1 and 2 Train A and B safety chiller rooms,

Elevation 778' on February 16, 2007

Fire Zone 2SB2A - Unit 2 Train A ECCS pump rooms, Elevation 773' on

February 16, 2007

Fire Zone 1CA - Unit 1 containment, all elevations on March 2, 2007

Fire Zone 2SA- Unit 2 Train B ECCS equipment rooms Elevations 773', 790',

810', and 831' on March 5, 2007

The inspectors completed six samples.

-6- Enclosure

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

The inspectors reviewed the licensees program for maintenance and testing for the

eight risk-important heat exchangers listed below. The inspectors performed the review

to ensure that these heat exchangers are capable of performing their required safety

function during the design basis accident. Specifically, the inspectors observed the

physical condition before and after cleaning activities and verified that the frequency of

monitoring and inspection was sufficient to detect degradation prior to loss of heat

removal capabilities below design requirements. Corrective action documents and

design basis documents were also reviewed by the inspectors. The service water

system and fouling monitoring program manager was also interviewed. The following

heat exchangers were reviewed for this inspection:

C On February 13, 2007, the inspectors observed the as found, cleaning, and as

left condition of the Unit 2 Safety Injection Pump 2-02 lube oil cooler.

C On February 20, 2007, the inspectors interviewed the system engineer and

observed the cleaning and as left condition of the Unit 2 Centrifugal Charging

Pump 2-02 lube oil cooler.

C On March 4, 2007, the inspectors observed the as found condition of the Unit 1

Train B EDG jacket water cooler.

C On March 20, 2007, the inspector interviewed the system engineer and

discussed the performance and condition of all four component cooling water

heat exchangers.

C On March 20, 2007, the inspectors interviewed the system engineer and

reviewed the as found, cleaning, and as left condition of the Unit1 Train B EDG

jacket water cooler.

The inspectors completed eight samples.

b. Findings

No findings of significance were identified.

-7- Enclosure

1R11 Licensed Operator Requalification (71111.11)

.1 Biennial Inspection (71111.11B)

a. Inspection Scope

The inspectors: (1) evaluated examination security measures and procedures for

compliance with 10 CFR 55.49; (2) evaluated the licensees sample plan for the written

examinations for compliance with 10 CFR 55.59 and NUREG-1021, as referenced in the

facility requalification program procedures; and (3) evaluated maintenance of license

conditions for compliance with 10 CFR 55.53 by review of facility records (medical and

administrative), procedures, and tracking systems for licensed operator training,

qualification, and watchstanding. In addition, the inspectors reviewed remedial training

and examinations for examination failures for compliance with facility procedures and

responsiveness to address areas failed. The inspectors also verified that on-shift

operators requiring prescription lenses for self-containment breathing apparatus (SCBA)

maintained their lenses secured in the control room.

Furthermore, the inspectors (1) interviewed seven personnel (four operators, two

instructors/evaluators, and a training supervisor) regarding the policies and practices for

administering examinations; (2) observed the administration of two dynamic simulator

scenarios to two requalification crews by facility evaluators, including an engineering

department manager, who participated in the crew and individual evaluations; and

(3) observed four facility evaluators administer five job performance measures (JPM),

including two in the control room simulator in a dynamic mode, and three in the plant

under simulated conditions. Each JPM was observed being performed by at least two

requalification candidates.

The inspectors also reviewed the biennial written examinations including two

remediation written examinations for a reactor operator and a senior reactor operator.

The inspectors verified question level of difficulty, knowledge level, and overlap between

successive exams and remediation exams. Additionally, quality audits and training self-

assessments, and training management meeting minutes were reviewed to ascertain

the health of their training feedback processes.

Of the 77 licensed operators taking the biennial examinations, 1 staff license failed a

JPM and 1 reactor operator and 1 senior reactor operator failed the written examination.

The inspectors also reviewed the remediation process for one individual, a JPM failure.

The inspectors also reviewed the results of the annual licensed operator requalification

operating examinations for 2006 and 2007. The results of the examinations were also

reviewed to assess the licensees appraisal of operator performance and the feedback

of that performance analysis to the requalification training program. Inspectors also

observed the examination security maintenance during the examination week.

b. Findings

No significant findings were identified.

-8- Enclosure

.2 Resident Inspector Quarterly Review (71111.11Q)

a. Inspection Scope

The inspectors observed a licensed operator requalification training scenario in the

control room simulator on February 16, 2007. The scenario began with a discussion of

the Integrated Plant Operations (IPO) procedure concerning reduced inventory, changes

involving the temporary reactor vessel head, and possible loss of reactor coolant

system (RCS) heat removal. The operations crew briefed the action of reducing RCS

inventory to 56 inches in accordance with IPO-010A. A loss of the Train B residual heat

removal (RHR) pump event occurred during the inventory reduction. Then the Train A

RHR pump began to experience erratic current and flow readings. The Train A pump

was manually secured. Abnormal condition procedure ABN-104 was entered due the

loss of the RHR system at reduced inventory. Inventory continued to decline, due to an

RCS leak, as operators began to reestablish heat removal. The scenario was

terminated after operators established RCS hot leg injection via the safety injection

pumps prior to RCS temperature reaching 212 degrees.

Simulator observations included formality and clarity of communications, group

dynamics, the conduct of operations, procedure usage, command and control, and

activities associated with the emergency plan. The inspectors also verified that

evaluators and operators were identifying crew performance problems as applicable.

On February 14, 2007, the inspectors also observed a requalification classroom training

session regarding the switchyard system changes, system operation, as well as industry

events. On February 16, 2007, the inspectors observed classroom training regarding

the upcoming Unit 1, Cycle 13 reactor core characteristics following steam generator

replacement.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Rule Implementation (71111.12)

a. Inspection Scope

The inspectors reviewed the sample listed below for items such as: (1) appropriate work

practices; (2) identifying and addressing common cause failures; (3) scoping in

accordance with 10 CFR 50.65(b) of the maintenance rule; (4) characterizing reliability

issues for performance; (5) trending key parameters for condition monitoring;

(6) charging unavailability for performance; (7) classification and reclassification in

accordance with 10 CFR 50.65(a)(1) or (a)(2); and (8) appropriateness of performance

criteria for SSCs/ functions classified as (a)(2) and/or appropriateness and adequacy of

-9- Enclosure

goals and corrective actions for SSCs/ functions classified as (a)(1). In addition, the

inspectors specifically reviewed events where ineffective equipment maintenance has

resulted in invalid automatic actuations of Engineered Safeguards Systems affecting the

operating units, when applicable. Items reviewed included the following:

C Spent fuel pool cooling system performance, reviewed on March 19, 2007

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

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

a. Inspection Scope

The inspectors reviewed selected activities regarding risk evaluations and overall plant

configuration control. The inspectors discussed emergent work issues with work control

personnel and reviewed the potential risk impact of these activities to verify that the

work was adequately planned, controlled, and executed. The activities reviewed were

associated with:

C Replacement of Reactor Makeup Water Pump 2-01 to Makeup Water Header

Isolation Valve XDD-0103 and related freeze seal, which isolated makeup water

to the Unit 2 RCS for approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> with the unit at 100 percent power

on January 4, 2007

Rescheduling of the Unit 1 Train B solid state safeguards sequencer

undervoltage relay test due to an Energy Reliability Council of Texas (ERCOT)

request to minimize maintenance that might result in a loss of generation

because of severe winter weather and available spinning reserves on

January 17, 2007

C Emergent troubleshooting and repair of Unit 1 Anticipated Transient Without

Scram (ATWS) Mitigating System Actuation Circuitry (AMSAC) system with

electric grid alerts and scheduled maintenance and testing of Unit 1 Train A

EDG, safety-related inverters, and reactor protection system surveillances during

the week of January 29, 2007

C Performance of the load test for the Outside Lift System, the crane and lift

structure outside the Unit 1 containment built for the steam generator and

reactor head replacement, coincident with an ERCOT advisory for reduced

spinning electrical reserves on February 9, 2007

C The Unit 1RF12 Outage Risk Assessment and defense-in-depth contingency

plans (DIDCP) on February 23-26, 2007

-10- Enclosure

C Outage of Unit 1 non-safeguards component cooling water train, concurrent with

full core offload to Spent Fuel Pool X-01, resulting in a configuration of only one

train of heat removal available for the spent fuel pool cooling system (Unit 2 non-

safeguards component cooling water train, which would be tripped on a Unit 2

loss of offsite power or safety injection), as evaluated in DIDCP 1RF-03,

reviewed on March 7, 2007

The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors: (1) reviewed plant status documents such as operator shift logs,

emergent work documentation, deferred modifications, and standing orders to

determine if an operability evaluation was warranted for degraded components;

(2) referred to the Updated Safety Analysis Report and design basis documents to

review the technical adequacy of licensee operability evaluations; (3) evaluated

compensatory measures associated with operability evaluations; (4) determined

degraded component impact on Technical Specifications (TSs); (5) used the

significance determination process to evaluate the risk significance of degraded or

inoperable equipment; and (6) verified that the licensee had identified and implemented

appropriate corrective actions associated with degraded components. The inspectors

interviewed appropriate licensee personnel to provide clarity to operability evaluations,

as necessary. Specific operability evaluations reviewed are listed below:

C Smart Form (SMF) SMF-2006-003263-00, to determine the operability of the Unit 2

EDG with Ultra Low Sulfur Diesel fuel, reviewed January 29, 2007

C DIDCP for Maintaining Unit 1 Containment Pressure DIDCP 1RF-22 and Evaluation

(EVAL) EVAL-2005-000658-03-00, to determine the operability of Unit 1 containment

with the proposal to cut the containment liner during Modes 5 and 6, reviewed on

March 5, 2007

C DIDCP for Temporary Power of Unit 1 SSWP 1RF-21, provided implementation steps

and evaluation of the operability of Unit 1 SSWP to support Unit 2 operation during

the refueling outage, including the potential for a dropped load to damage the safety-

related power source to the Unit 1 SSWP, reviewed on March 9, 2007

C EVAL-2007-005556-01-02, to determine SSWP 2-02 operability following pump

replacement and failed surveillance test on February 21, 2007, reviewed the week of

March 12, 2007

C EVAL-2006-004030-02-00 for ECCS train operability following personnel entries into

-11- Enclosure

Units 1 and 2 containment recirculation sumps at full reactor power, reviewed

March 21, 2007

C EVAL-2006-004064-04-00 for Unit 2 RCS due to a leak in the hydraulic line to Steam

Generator 2-04 upper lateral hydraulic snubber, reviewed March 23, 2007

The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications (71111.17B)

a. Inspection Scope

The inspectors reviewed permanent plant modification documentation related to the

steam generator and reactor vessel head replacement project for Unit 1. The results of

Inspection Procedure 71111.17B Permanent Plant Modifications, covering the biennial

permanent plant modifications will be documented separately in NRC Inspection

Report 05000445/2007006, developed specifically for the Steam Generator and Reactor

Vessel Head Replacement Project. No permanent plant modifications unrelated to the

steam generator replacement project were reviewed.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors witnessed or reviewed the results of the postmaintenance tests for the

following maintenance activities:

Unit 2, Train B EDG following replacement of the right bank number 3 fuel injector

pump in accordance with Procedure OPT- 214B, Diesel Generator Operability Test,

Revision 13, observed on January 24, 2007

Unit 1 Motor Driven Auxiliary Feedwater Pump SSW Suction Valve 1-HV-2481,

following a major inspection of the motor operator, in accordance with OPT-502A,

AFW/SSW Crosstie Valves, Revision 8, reviewed on January 24, 2007

Unit 2 Centrifugal Charging Pump 2-01, following lube oil cooler cleaning, and motor

oil change, in accordance with OPT-201B, Charging System, Revision 7 and SOP-

103B, Chemical and Volume Control System, Revision 11, observed on January 30,

2007

-12- Enclosure

Unit 1 Train B Safety Chilled Water Recirculation Pump 1-06, following an oil change,

lube oil cooler cleaning, and replacement of the motor cooling fan, in accordance with

OPT-209A, Safety Chilled Water System, Revision 13, reviewed on March 11, 2007

Unit 1 RHR System to Cold Leg Containment Isolation Valve 1-8890A, following

elastomer and subcomponent replacement, in accordance with OPT-512A, RHR and

SI Subsystem Valve Test, Revision 9, reviewed on March 17, 2007

In each case, the associated work orders and test procedures were reviewed in

accordance with the inspection procedure to determine the scope of the maintenance

activity and to determine if the testing was adequate to verify equipment operability.

The inspectors completed five samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Outage Activities (71111.20)

a. Inspection Scope

The inspectors evaluated licensees 1RF12 activities to ensure that risk was considered

when developing and when deviating from the outage schedule, the plant configuration

was controlled in consideration of facility risk, mitigation strategies were properly

implemented, and TS requirements were implemented to maintain the appropriate

defense-in-depth. Specific outage inspections performed and outage activities reviewed

and/or observed by the inspectors included:

Discussions and review of the outage schedule concerning risk with the Outage

Manager

Unit shutdown and cooldown

Containment walkdowns to identify indications of reactor coolant leakage, evaluate

material condition of equipment not normally available for inspection, inspect fire

protection equipment and fire hazards, observe radiation protection postings and

barriers, and evaluate coatings and debris for potential impact on the recirculation

containment sumps

RCS instrumentation including Mansell level instrumentation

Defense in depth and mitigation strategy implementation

Containment closure capability

Verification of decay heat removal system capability

-13- Enclosure

Spent fuel pool cooling capability

Reactor water inventory control including flow paths, configurations, alternate means

for inventory addition, and controls to prevent inventory loss

Controls over activities that could affect reactivity

Refueling activities that included fuel offloading, and fuel transfer

Implementation of procedures for foreign material exclusion

Electrical power source arrangement

Containment recirculation sump inspection after modification of sump filters

Licensee identification and resolution of problems related to refueling activities

Additional inspections were performed in accordance with Inspection Procedure 71007,

Reactor Vessel Head Replacement Inspection, Inspection Procedure 50001, Steam

Generator Replacement Inspection, and will be documented in Inspection Report 05000445/2007006.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors evaluated the adequacy of periodic testing of important nuclear plant

equipment, including aspects such as preconditioning, the impact of testing during plant

operations, and the adequacy of acceptance criteria. Other aspects evaluated included

test frequency and test equipment accuracy, range, and calibration; procedure

adherence; record keeping; the restoration of standby equipment; test failure

evaluations; system alarm and annunciator functionality; and the effectiveness of the

licensees problem identification and correction program. The following surveillance test

activities were observed and/or reviewed by the inspectors:

Unit 1 Motor Driven Auxiliary Feedwater Pump 1-02 in accordance with work order

(WO) WO-5-06-505610-AD and OPT-206A, AFW System, Revision 25, reviewed

on January 24, 2007

Unit 2 Turbine Driven Auxiliary Feedwater Pump 2-01 inservice testing in accordance

with OPT-206B, AFW System, Revision 18, reviewed on February 1, 2007

Unit 1 RHR Pump 1-01 surveillance test in accordance with OPT-203A, Residual

Heat Removal System, Revision 15, observed on February 1, 2007

-14- Enclosure

Unit 1 static load test of the steam generator and reactor vessel head outside

(containment) lift system, in accordance with WO-2-06-167488-00, on

February 9, 2007

C Unit 1 Main Steam Safety Valves 1MS-0023, 1MS-0059, 1MS-0060, 1MS-0095, 1MS-

0129, and 1MS-0130 surveillance testing in accordance with Mechanical Section -

Maintenance Manual Procedure (MSM)-S0-8702, Main Steam Safety Valve Testing,

Revision 3, reviewed on February 21, 2007

C Unit 1 Train B 6.9kV bus manual transfer, automatic transfer on undervoltage and

EDG 1-02 output breaker trip on safety injection signal surveillance testing in

accordance with Maintenance Section - Electrical Manual (MSE) procedure

MSE-S1-0602B, Electrical UV Relay Test, Response Time Test and Bus Transfer

Test, Revision 0, performed on March 5, 2007 and reviewed on March 12 - 13, 2007

Unit 2 SSWP 2-02 inservice test in accordance with OPT-207B, "Service Water

System," Revision 12, reviewed week of March 12, 2007

The inspectors completed seven samples.

b. Findings

Introduction: A Green NRC identified noncited violation of TS 5.4.1.e was identified for

the failure to establish, implement, and maintain written procedures for the inservice

testing program. Station Administration Procedure (STA) STA-711, Inservice Testing

Program for Pumps and Valves required a new set of reference values be determined

following pump replacement and all subsequent test results be compared to the new

reference values. Station Service Water Pump 2-02 was declared operable on October

19, 2006, following pump replacement and, although the new pumps performance was

fully acceptable, the inservice testing requirements to establish new reference values

were not performed. Subsequent surveillance tests were performed with the old

reference value as the basis for the test acceptance criterion which was not in

accordance with the ASME code.

Description: On February 21, 2007, surveillance testing of SSWP 2-02 was performed

in accordance with OPT-207B, Service Water System, Revision 12, Section 8.3, and

Data Sheet OPT-207B-5, SSWP 2-02 Data Sheet, Revision 13, to satisfy the quarterly

pump performance surveillance. The measured pump flow of 12,996 gallons per

minute (gpm) did not meet the acceptance criterion (new reference value of 16,761

gpm). The pump was declared inoperable and all appropriate actions were taken,

including reviewing past pump performance. The licensee determined that the pump

had met the surveillance test criterion (old reference value of 13,045 gpm) when last

performed on November 27, 2006, and that the surveillance procedure Data Sheet

OPT-207B-5 had been revised on December 1, 2006, changing to the new reference

value. The licensee issued Revision 14 to the data sheet using the Revision 12

acceptance criterion (i.e., old reference values), evaluated the test results against this

criterion and declared the pump operable.

-15- Enclosure

During Unit 2 refueling outage 2RF09 the SSWP 2-02 had been replaced. On

October 18, 2006, the pump was flow tested in accordance with Equipment Test

Procedure (ETP) ETP-215B, Service Water Pump Test, Revision 2, for the purpose of

obtaining reference values for pump performance (flow, developed pump head, and

vibrations). However, the test did not comply with the applicable ASME OMa

Code-1999 Addenda to ASME OM Code - 1998, Code for Operation and Maintenance

of Nuclear Power Plants which required at least 5 points to be measured after pump

conditions are as stable as the system permits (pump shall be run at least 2 minutes at

each point). Instead, ETP-215B had collected pump data with an automated data

acquisition system as the discharge valve opened on pump start vice throttling to

establish distinct, stable flow conditions. The ETP-215B also collected data at a flow

rate of approximately 16,000 gpm with the intent of using this for the new reference

value during subsequent surveillance testing.

On October 19, 2006, EVAL-2006-003466-02-00 was performed to determine the

operational readiness of the pump based on the results of the ETP-215B. SSWP 2-02

was declared operable based on a comparison of the pump start data with the pump

curve in the Design Basis Document DBD-ME-233, Station Service Water System,

Revision 16, and a comparison of the pump full flow data from ETP-215B to the DBD

design flow of 15,556 gpm. EVAL-2006-003466-02-00 did not establish a new

reference value nor verify whether the previous reference value in the surveillance

procedure was still valid. The DBD design flow value of 15,556 gpm was subsequently

determined to be in error, the actual value should have been 16,456 gpm.

On November 8, 2006, EVAL-2006-003466-01-00 was performed to rebaseline the

SSWP 2-02 based on the ETP-215B results and establish a new reference value for

surveillance procedure OPT-207B, Service Water System. An action item was created

to incorporate the new reference value into the procedure, with a due date of

December 25, 2006. In this evaluation, the full flow value of 16,761 gpm was incorrectly

provided as the reference value (for Section 8.3 of the OPT-207B) which was intended

to be approximately 16,000 gpm. Furthermore, Section 8.3 established a system

configuration with pump developed head of approximately 90 psid, which corresponds to

the previous reference value for a flow of approximately 13,000 gpm. It was not

communicated to the procedure writers that the new reference value for a flow of

16,000 gpm (or 16,761 gpm) required a different system configuration for Section 8.3.

On November 27, 2006, OPT-207B was performed to satisfy the routine quarterly

surveillance requirement. OPT-207B had not yet been revised with the new reference

value and the SSWP 2-02 was declared operable based on the previous reference

value. On December 1, 2006, OPT-207B was revised to incorporate the new reference

value from EVAL-2006-003466-01-00. Section 8.3 of the procedure still established

system conditions of pump developed head of approximately 90 psid, but with a flow

rate (16,761 gpm) that was more appropriate for a developed head of approximately

57 psid. On February 21, 2007, when the new reference values were used for the first

time, SSWP 2-02 failed to satisfy the test acceptance criterion.

On February 22, 2007, a plant event review committee (PERC) meeting was held to

determine the cause of SSWP 2-02 failing to meet the acceptance criterion of Data

Sheet OPT-207B-5, Revision 13. Although the PERC came to the conclusion that the

-16- Enclosure

data sheet was incorrect, other related issues remained unresolved, including the

inspectors concerns about the operability of SSWP 2-02 and the basis for determining

that the pump was operable.

On February 28, 2007, another PERC was held to address these issues and to identify

other contributing causes of the inadequate surveillance Procedure OPT-207B. On

March 13, 2007, EVAL-2007-000556-01-02 provided the technical justification for the

operability of SSWP 2-02, based on comparison of the new pump performance obtained

from ETP-215B and both surveillance tests with the correct design flow requirement of

16,456 gpm at full flow, as well as the DBD pump curve and the previous pump

performance. This evaluation also documented the failure to comply with the ASME

Code following the pump replacement, in that an adequate baseline pump test had not

been performed, nor was a new reference value determined. ETP-215B has been

revised to incorporate the ASME requirements and will be performed at the next

available work window. New reference values and limits will be determined and

incorporated into OPT-207B.

Analysis: The performance deficiency was the failure to implement STA-711 Inservice

Testing Program for Pumps and Valves, which required (1) new reference values be

determined by the test method in the ASME OM Code and (2) the new reference valves

be used for all subsequent testing. The inspectors determined that the finding is more

than minor because it affected the mitigation system cornerstone attribute of human

performance (pre-event) and objective to ensure the capability of the SSW system to

respond to initiating events with sufficient flow to prevent core damage. This finding

does not affect the initiating event of loss of service water because the potential

consequence is not a loss of flow but degraded flow. Degraded flow would not

challenge the SSW systems ability to provide operational cooling to the component

cooling water system. This finding is also similar to Examples 3.j and 3.k of Appendix E

of IMC-0612, in that it is not minor because it resulted in a condition where there was

now a reasonable doubt on the operability of the SSWP 2-02, and programmatic

deficiencies were identified in the implementation of the Inservice Testing Program that

could lead to worse errors if not corrected. The significance of the finding is very low

(Green) because the SSWP 2-02 was always fully capable of performing its safety

function. The finding was screened as Green in Phase 1 of the significance

determination process because it did not involve an actual loss of any safety function,

nor contributed to external event initiated core damage accident sequences (i.e.,

initiated by seismic, flooding, or severe weather event).

The finding had a crosscutting aspect in the area of human performance with a

resources component, in that, the licensee failed to ensure complete, accurate and

up-to-date procedures were available and adequate to ensure nuclear safety.

Specifically, ETP-215B, Service Water Pump Test, Revision 2 did not comply with the

ASME Code requirements for testing following pump repair, OPT-207B, Service Water

System, Revision 12 with Data Sheet OPT-207B-5 R-13 was not adequate for the

quarterly surveillance test, and no procedure ensured the new reference values were

incorporated into surveillance procedures prior to their use.

Enforcement: Technical Specification 5.4.1.e requires written procedures be

established and implemented for the Inservice Testing Program. Station Administrative

-17- Enclosure

Procedure STA-711, Inservice Testing Program for Pumps and Valves, Revision 6,

Section 6.3.3 required that when a reference value or set of reference values may have

been affected by repair, replacement, or routine maintenance of a pump, the

requirements of ASME OM Code - 1998, Code for Operation and Maintenance of

Nuclear Power Plants, Section ISTB-3310 shall be met. ASME OMa Code - 1999

Addenda to ASME OM Code, Section ISTB-3310 required a new reference value or set

of values shall be determined in accordance with ISTB-3300, or the previous value

reconfirmed by a comprehensive or Group A test run before declaring the pump

operable. Deviations between the previous and new set of reference values shall be

evaluated, and verification that the new values represent acceptable pump operation

shall be placed in the record of tests. The ASME OM Code also required all subsequent

test results shall be compared to new reference values. Contrary to the above,

SSWP 2-02 was declared operable on October 19, 2006, without determining the

required new reference values in accordance with the required test method.

Subsequent surveillance test results were compared to the previous reference values

without first reconfirming their validity. This violation was entered into the licensees

corrective action program as SMF-2007-000556-00. Since this violation is of very low

safety significance and has been entered into the corrective action program, it is being

treated as a noncited violation, consistent with Section VI.A.1 of the NRC Enforcement

Policy (NCV 05000446/2007002-01, Failure to Perform Required Inservice Testing

Following Pump Replacement).

4. OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

Initiating Events

a. Inspection Scope

The inspectors reviewed a sample of performance indicator data submitted by the

licensee regarding the initiating events cornerstone to verify that the licensees data was

reported in accordance with the requirements of Nuclear Energy Institute NEI 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 4. The sample

included data taken from control room operator logs, the SMF database, and licensee

event reports for January 2005 through December 2006 for the following performance

indicators:

Units 1 and 2, unplanned scrams per 7,000 critical hours

Units 1 and 2, unplanned scrams with loss of normal heat removal

Units 1 and 2, unplanned power changes per 7,000 critical hours

During plant tours, inspectors periodically determined if access to high radiation areas

was properly controlled and if potentially unmonitored release pathways were present.

The inspectors completed six samples.

-18- Enclosure

b. Findings

No findings of significance were identified.

4OA2 Problem Identification and Resolution (71152)

Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As required by Inspection Procedure 71152, "Identification and Resolution of Problems,

and in order to identify repetitive equipment failures or specific human performance

issues for follow-up, the inspectors performed a routine screening of all items entered

into the licensees corrective action program. This review was accomplished by

reviewing the licensees computerized corrective action program database, reviewing

hard copies of selected SMFs, and attending related meetings such as PERC meetings.

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up (71153)

.1 (Closed) LER 05000446/2006-002 Reactor Trip Due to a Secondary Transient Initiated

During Load Rejection Testing

On October 27, 2006, Unit 2 was in Mode 1 at 28 percent power performing planned

25 MWe load reject tests following digital modifications to the protection circuitry of the

turbine generator. The third 25 MWe swing resulted in a divergent oscillation in the

secondary system. Operators identified the oscillations and took manual control of the

feedwater system, but the level in Steam Generator 2-02 reached the HI-HI setpoint.

The HI-HI level caused a trip of the main turbine and the isolation of main feedwater.

The operators manually tripped the Unit 2 reactor. The licensee determined that there

was enough information gathered to declare testing of the turbine generator digital

upgrade was complete. The licensees corrective actions included: (1) modifying the

procedure for sequencing secondary system pumps, (2) changing gain settings for the

main feedwater pump speed controller back to the previous settings, which had been

changed at 100 percent power to help maintain a tighter feedwater flow rate band and

thus operate closer and more consistently at 100 percent power, and (3) implementing

lessons learned training. More specific event details can be found in Section 4OA3,

Event Followup, of Inspection Report 2006-005. The LER was reviewed by the

inspectors and no findings of significance were identified and no violations of NRC

requirements occurred. The licensee documented the event in their corrective action

program in SMF-2006-003632-00. This LER is closed.

-19- Enclosure

.2 (Closed) LER 05000446/2006-003 Unit 2 Reactor Trip Due to Feedwater Regulating

Valve Malfunction

On October 29, 2006, Unit 2 was in Mode 1 at 80 percent power and holding for Xenon

stabilization, when a manual reactor trip was initiated due to Steam Generator 2-03 level

lowering uncontrollably. The licensee investigated and determined that Solenoid

Valve SV-2 associated with Feedwater Regulating Control Valve 2-FCV-530, had a

loose wire. The loss of continuity resulted in the loss of air between the valve positioner

and the valve operator diaphragm, causing the flow control valve to fail closed. The

licensee was able to duplicated the failure in the valve workshop. Corrective actions

included: (1) reviewing and checking the other Unit 2 feedwater regulating control valves

on Unit 2 prior to restart, (2) inspecting Unit 1 feedwater regulating control valves, and

(3) modifying the maintenance procedure to ensure that the wires in the terminal blocks

are tight. More specific details can be found in Section 4OA3.2, Event Followup, of

Inspection Report 2006-005. The LER was reviewed by the inspectors and no findings

of significance were identified and no violations of NRC requirements occurred. The

licensee documented the event in the corrective action program as

SMF-2006-003660-00. This LER is closed.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On January 24, 2007, the inspectors presented the inspection results of the licensed

operator requalification inspection to Mr. T. Hope, Manager, Regulatory Affairs, and

other members of the licensees management staff at an exit interview. The licensee

acknowledged the findings presented. The inspectors also asked the licensee whether

any materials examined during the inspections should be considered proprietary. No

proprietary information was identified.

On February 9, 2007, the inspectors presented the safety evaluation and permanent

plant modifications inspection results to Mr. S. Smith, Site Engineering Director, and

other members of the staff who acknowledged those results. No proprietary information

was included in this report.

On March 29, 2007, the inspectors presented the resident inspection results to

Mr. M. Lucas, Vice President Nuclear Engineering and Support, and other members of

licensee management. The inspectors confirmed that proprietary information was not

provided or examined during the inspection.

On April 20, 2007, the inspectors held a re-exit meeting with Mr. T. Hope, Manager of

Regulatory Performance, to present changes in the characterization of violations

identified during the inspection period and presented in the March 29 exit meeting.

ATTACHMENT: SUPPLEMENTAL INFORMATION

-20- Enclosure

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

D. Bersi, Steam Generator Replacement Project, Component Design/Fabrication Lead

O. Bhatty, Inservice Test Engineer

M. Blevins, Senior Vice President and Chief Nuclear Officer

J. Brabec, Steam Generator Replacement Project, Installation Manager/Asst. Project Manager

G. Casperson, Supervisor, Simulator

J. Finneran, Steam Generator Replacement Project, Project Engineering Manager

R. Flores, Site Vice President, Nuclear Operations

D. Haggerty, Project Engineer, Bechtel

N. Hood, Project Engineering Manager

T. Hope, Manager, Regulatory Affairs

M. Killgore, Engineering Support Director

D. Kissinger, Design Engineering Analysis Engineer

B. Lichtenstein, Engineer, Risk and Reliability, Westinghouse

M. Lucas, Vice President Nuclear Engineering and Support

F. Madden, Director, Regulatory Affairs

S. Maier, Design Engineering Analysis Manager

B. Mays, Steam Generator Project Manager

E. Meaders, Outage Manager

J. Meyer, Technical Support Manager

K. Pitilli, Design Engineering Analysis Engineer

W. Reppa, JET Manager

S. Sewell, Nuclear Training Manager

J. Skelton, System Engineer

R. Smith, Director, Operations

S. Smith, Director, System Engineering

G. Struble, Operations Training Supervisor

D. Tirsun, Engineer, Risk and Reliability, Westinghouse

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed

05000446/2007002-01 NCV Failure to perform required inservice testing

following pump replacement (Section 1R22)

A-1 Attachment

Closed

05000446/2006-002 LER Reactor Trip Due to a Secondary Transient

Initiated During Load Rejection Testing

(Section 4OA3.1)

05000446/2006-003 LER Unit 2 Reactor Trip Due to Loss of

Feedwater Regulating Valve Malfunction

(Section 4OA3.2)

Discussed

None

LIST OF DOCUMENTS REVIEWED

Section 1R02: Evaluations of Changes, Tests, or Experiments

Evaluations

Document Number Title/Description Revision

59EV-2003-002426-03-00 Multiflex 3.0 Computer Code 0

59EV-2004-002661-01-00 Temporary Bypass or reset of containment polar 0

crane protection devices

59EV-2004-001255-02-00 Upgrade the Unit 2A and B Train DG 0

Exciter/Voltage Regulator

59EV-2006-003867-01-00 Procedural changes to control bypassing of 0

Containment Crane Anti-Collision Control System

59EV-2004-000773-02-00 Final phase replacement of the Unit 2 Turbine- 0

Generator Protection Systems Analog to Digital

59EV-2001-001672-02-01 Design Modification to replace Unit 1 Turbine 1

Generator analog controls to digital controls

10 CFR 50.59 Screenings

Document Number Title/Description Revision

59SC-2005-000658-02-01 Rigging and Transport of OSGs, RSGs, ORVH, 1

and RRVH

59SC-2004-002831-01-01 Add stops to new fuel elevator for reconstitution of 1

fuel

A-2 Attachment

59SC-2005-001537-01-00 Accept manufactures minimum wall thickness 0

violation of ASME Section III piping

59SC-2000-000526-05-01 Extend LAN in plant. 1

59SC-2000-002072-01-00 Revise Plant Flow Diagrams M1-0222 and 0

M2-0222 to show valve operations.

59SC-2004-003549-03-00 Change to allow Unit 1 & 2 Seal Steam Controllers 0

to transfer from automatic to manual control

59SC-2005-004516-01-00 Abandon inoperable incore thermocouple 0

1-TE-0024

59SC-2006-003564-01-00 Delete the stroke time acceptance criteria for AFW 0

Steam Supply Valves 1/2-HV-2452-1, 2

59SC-2006-003609-01-00 Comp Actions for 2-HV-2417A stuck open 0

59SC-2002-001361-01-00 Add jack-bolts to CCW Motors 0

59SC-2005-001630-01-00 Penetration Seal Design 0

59SC-2005-003364-09-01 RWST Level Alarm Setpoint & Logic Changes 1

59SC-2005-004280-01-00 Revise DBD-ME-233 to change low pressure 0

alarm setpoint

59SC-2005-001785-01-00 Add valve to isolate leakage past valve 2CO-0300 0

59SC-2004-001702-00-00 Installed Components for New Grated Barriers 0

Applicability Determinations

2004-003549-03-00 - Change in Seal Steam controller operating system. Automatic to Manual

Function.

2004-002831-01-01 - New Fuel elevator for reconstitution.

2005-004516-01-00 - Abandon inoperable incore thermocouple

Condition Reports (SMART Forms)

2005-000702-00 2005-002931-00 2006-002181-00 2006-002830-00

2005-001955-00 2005-003271-00 2006-002548-00 2006-002963-00

2005-002136-00 2005-003748-00 2006-002575-00 2006-003234-00

2005-002224-00 2006-000032-01 2006-002606-00 2006-003337-00

A-3 Attachment

Section 1R05: Fire Protection (71111.05Q)

Comanche Peak Steam Electric Station Fire Protection Report, Unit 1 and Unit 2, Revision 25

STA-729, Control of Transient Combustibles, Ignition Sources and Fire Watches, Revision 7

FPI-101A, Unit 1 Safeguards Building Elevation 773'-0" Train A & B - RHR, SI & CS Pump

Rooms, Revision 3

FPI-101B, Unit 2 Safeguards Building Elevation 773'-0" A & B RHR, SI & Containment

Spray Pump Rooms, Revision 1

FPI-102A, Unit 1 Safeguards Building Elevation 790'-0", Revision 3

FPI-102B, Unit 2 Safeguards Building Elevation 790'-0", Revision 2

FPI-103A, Unit 1 Safeguards Building Elevation 810"-6" Rad, Pen. Area & Elec. Equip. Rm,

Revision 3

FPI-103B, Unit 2 Safeguards Building Elevation 810"-6" Rad, Pen. Area & Elec. Equip. Rm,

Revision 3

FPI-106A, Unit 1 Safeguards Building Elevation 831'-6" Main Corridor, RB Assess, & Electrical

Equi-pment Area, Revision 4

FPI-107A, U1 Safeguards Building, Elevation 852'-6" Electrical Equipment Area & FW

Penetration Area, Revision 3

FPI-107B, U2 Safeguards Elevation. 852' Electrical Equipment Area & Feedwater Penetration

Area, Revision 2

FPI-201A, Unit 1 Containment Building Elev. 808'-0", Revision 3

FPI-202A, Unit 1 Containment Building Elev. 832'-6", Revision 3

FPI-203A, Unit 1 Containment Bldg. Elevation 860'-0", Revision 3

FPI-204A, Unit 1 Containment Building, Elev. 905'-0", Revision 3

FPI-406, Auxiliary Building Elevation 831'-6", Revision 4

Section 1R11: Licensed Operator Requalification - Biennial Inspection (71111.11B)

Procedures

TRA-204, "Licensed Operator Requalification Training" Revision 14

A-4 Attachment

TRA-204, Attachment 8.A "Licensed Operator Annual Requalification Examination

Development and Security Guidelines" Revision 14

TRA-204, Attachment 8.B "Requalification Training Commitments" Revision 14

NTP-103 "Design" Revision 12

NTP-105, "Implementation" Revision 18

ODA-315, "Licensed Operator Maintenance Tracking" Revision 5

ABN-302,"Feedwater, Condensate, Heater Drain System malfunction," Revision 13

ABN-107,"Emergency Boration," Revision 7

ABN-705, "Pressurizer Pressure Malfunction," Revision 11

ABN-707, "Steam Flow Instrument Malfunction," Revision 6

ABN-712, "Rod Control Malfunction," Revision 10

EOP-0.0A, "Reactor Trip or safety Injection," Revision 8

EOP-1.0A, "Loss of Reactor or Secondary Coolant," Revision 8

EOP-2.0A, "Faulted Steam Generator Isolation," Revision 8

EOS-1.1A, "Safety Injection Termination," Revision 8

EOS-1.3A, "Transfer to Cold Leg Recirculation," Revision 8

FRP-0.1A, "Response To Imminent Pressurized Thermal Shock Condition," Revision 8

FRZ-0.1A, "Response To High Containment Pressure," Revision 8

ML071271010

Text

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