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IR 05000361-07-005, IR 5000362-07-005, on 9/27/07-12/31/2007, San Onofre Nuclear Generating Station, Units 2 & 3; Integrated Resident and Regional Report; Emergent Work, Operability Evaluations, Occupational Radiation Safety... and Notice o
	ML080440436
Person / Time
Site:	San Onofre
Issue date:	02/13/2008
From:	Clark J; NRC/RGN-IV/DRP/RPB-E
To:	Rosenblum R; Southern California Edison Co
References
	EA-08-051, FOIA/PA-2011-0157 IR-07-005
	Download: ML080440436 (65)
	v • d • e

February 13, 2008

EA-08-051

Richard M. Rosenblum

Senior Vice President and

Chief Nuclear Officer

Southern California Edison Company

San Onofre Nuclear Generating Station

P.O. Box 128

San Clemente, CA 92674-0128

SUBJECT: SAN ONOFRE NUCLEAR GENERATING STATION - NRC INTEGRATED

INSPECTION REPORT 05000361/2007005; 05000362/2007005 AND NOTICE OF

VIOLATION

Dear Mr. Rosenblum:

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

inspection at your San Onofre Nuclear Generating Station, Units 2 and 3 facility. The enclosed

integrated report documents the inspection findings, which were discussed on December 21,

2007, and February 13, 2008, with Mr. R. Ridenoure and other members of your staff.

The inspection examined activities conducted under your licenses as they relate 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.

One violation is cited in the enclosed Notice of Violation (Notice) and the circumstances

surrounding this violation are described in detail in the enclosed report. The violation involved

your failure to implement effective corrective actions to ensure thermal overloads associated

with safety-related equipment would not fail prematurely (EA-08-051). Although determined to

be of very low safety significance (Green), this violation is being cited because not all the

criteria specified in Section VI.A.1 of the NRC Enforcement Policy for a noncited violation (NCV)

were satisfied. Specifically, Southern California Edison failed to restore compliance within a

reasonable time after the violation was first identified in Inspection

Report 05000361;05000362/2006005. Please note that you are required to respond to this

letter and should follow the instructions specified in the enclosed Notice when preparing your

response. The NRC will use your response, in part, to determine whether further enforcement

action is necessary to ensure compliance with regulatory requirements.

This report also documents three NRC identified and self-revealing findings of very low safety

significance (Green). These findings were determined to involve violations of NRC

requirements. Additionally, one licensee-identified violation which was determined to be of very

low safety significance is listed in this report. However, because of the very low safety

Southern California Edison Company -2-

significance and because they were entered into your corrective action program, the NRC is

treating these findings as NCVs consistent with Section VI.A of the NRC Enforcement Policy. If

you contest these NCVs, 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 copies to the Regional

Administrator, U.S. Nuclear Regulatory Commission 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 San

Onofre Nuclear Generating Station, Units 2 and 3, facility.

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).

Sincerely,

/RA/

Jeffrey A. Clark, Chief

Project Branch E

Division of Reactor Projects

Dockets: 50-361

50-362

Licenses: NPF-10

NPF-15

Enclosures:

Notice of Violation

NRC Inspection Report 05000361/2007005; 05000362/2007005

w/Attachment: Supplemental Information

cc w/enclosure:

Mr. Ross T. Ridenoure Gary L. Nolff

Vice President and Site Manager Assistant Director-Resources

Southern California Edison Company City of Riverside

San Onofre Nuclear Generating Station 3900 Main Street

P.O. Box 128 Riverside, CA 92522

San Clemente, CA 92674-0128

Mark L. Parsons

Chairman, Board of Supervisors Deputy City Attorney

County of San Diego City of Riverside

1600 Pacific Highway, Room 335 3900 Main Street

San Diego, CA 92101 Riverside, CA 92522

Southern California Edison Company -3-

Dr. David Spath, Chief Mr. James T. Reilly

Division of Drinking Water and Southern California Edison Company

Environmental Management San Onofre Nuclear Generating Station

California Department of Health Services P.O. Box 128

850 Marina Parkway, Bldg P, 2nd Floor San Clemente, CA 92674-0128

Richmond, CA 94804

Chief, Radiological Emergency

Michael J. DeMarco Preparedness Section

San Onofre Liaison National Preparedness Directorate

San Diego Gas & Electric Company Technological Hazards Division

8315 Century Park Ct. CP21G Department of Homeland Security

San Diego, CA 92123-1548 1111 Broadway, Suite 1200

Oakland, CA 94607-4052

Director, Radiological Health Branch

State Department of Health Services

P.O. Box 997414 (MS 7610)

Sacramento, CA 95899-7414

Mayor

City of San Clemente

100 Avenida Presidio

San Clemente, CA 92672

James D. Boyd, Commissioner

California Energy Commission

1516 Ninth Street (MS 34)

Sacramento, CA 95814

Douglas K. Porter, Esq.

Southern California Edison Company

2244 Walnut Grove Avenue

Rosemead, CA 91770

A. Edward Scherer

Southern California Edison Company

San Onofre Nuclear Generating Station

P.O. Box 128

San Clemente, CA 92674-0128

Mr. Steve Hsu

Department of Health Services

Radiologic Health Branch

MS 7610, P.O. Box 997414

Sacramento, CA 95899-7414

Southern California Edison Company -4-

Electronic distribution by RIV:

ROPreports

Regional Administrator (EEC)

DRP Director (DDC)

DRS Director (RJC1)

DRS Deputy Director (ACC)

Senior Resident Inspector (CCO1)

Branch Chief, DRP/E (JAC)

Senior Project Engineer, DRP/E (GDR)

Senior Project Engineer, DRP/E (GBM)

Team Leader, DRP/TSS (CJP)

RITS Coordinator (MSH3)

DRS STA (DAP)

V. Dricks, PAO (VLD)

D. Pelton, OEDO RIV Coordinator (DLP1)

SO Site Secretary (vacant)

MVasquez (GMV)

N Hilton, OE

June Cai, OE

John Wray, OE

Starkey, OE - DRS

Mary Ann Ashley, NRR

SUNSI Review Completed: _GBM__ ADAMS: WYes G No Initials: __GBM_

W Publicly Available G Non-Publicly Available G Sensitive W Non-Sensitive

R:\_REACTORS\_SO23\2007\SO2007-05RP-CCO.wpd ADAMS ML080440436

RIV:RI:DRP/E SRI:DRP/E SPE:DRP/E C:DRS/PSB C:DRS/OB

GMiller CCOsterholtz GReplogle MPShannon RELantz

/RA/ /RA teleph./ /RA electronic/ /RA/ /RA/

02/13/08 02/13/08 02/13/08 02/12/08 02/12/08

C:DRS/EB C:DRS/PEB SES/ACES C:DRP/E

RLBywater LJSmith GMVasquez JAClark

/RA/ /RA NOKeefe for/ /RA/ /RA GMiller for/

02/13/08 02/11/08 2/12/08 02/13/08

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

NOTICE OF VIOLATION

Southern California Edison Co. Docket No. 50-361;362

San Onofre Nuclear Generating Station License No. NPF-10;15

EA 08-051

During an NRC inspection conducted on September 27 through December 31, 2007, a violation

of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the

violation is listed below:

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that

measures shall be established to ensure that for significant conditions adverse to

quality, the cause of the condition is determined and corrective action taken to preclude

repetition.

Contrary to this, from February 6 through August 8, 2007, the licensee failed to take

corrective actions to preclude repetition of the premature tripping of thermal overloads

for safety-related equipment, a significant condition adverse to quality.

This violation is associated with a Green SDP finding.

Pursuant to the provisions of 10 CFR 2.201, Southern California Edison Company is hereby

required to submit a written statement or explanation to the U.S. Nuclear Regulatory

Commission, ATTN: Document Control Desk, Washington, DC 20555 with a copy to the

Regional Administrator, Region IV, and a copy to the NRC Resident Inspector at the facility that

is the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of

Violation (Notice). This reply should be clearly marked as a "Reply to a Notice of Violation;

EA-08-051" and should include: (1) the reason for the violation, or, if contested, the basis for

disputing the violation or severity level, (2) the corrective steps that have been taken and the

results achieved, (3) the corrective steps that will be taken to avoid further violations, and

(4) the date when full compliance will be achieved. Your response may reference or include

previous docketed correspondence, if the correspondence adequately addresses the required

response. If an adequate reply is not received within the time specified in this Notice, an order

or a Demand for Information may be issued as to why the license should not be modified,

suspended, or revoked, or why such other action as may be proper should not be taken.

Where good cause is shown, consideration will be given to extending the response time.

If you contest this enforcement action, you should also provide a copy of your response, with

the basis for your denial, to the Director, Office of Enforcement, United States Nuclear

Regulatory Commission, Washington, DC 20555-0001.

Because your response will be made available electronically for public inspection in the NRC

Public Document Room or from the NRCs document system (ADAMS), accessible from the

NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should

not include any personal privacy, proprietary, or safeguards information so that it can be made

available to the public without redaction. If personal privacy or proprietary information is

necessary to provide an acceptable response, then please provide a bracketed copy of your

response that identifies the information that should be protected and a redacted copy of your

response that deletes such information. If you request withholding of such material, you must

ENCLOSURE 1

specifically identify the portions of your response that you seek to have withheld and provide in

detail the bases for your claim of withholding (e.g., explain why the disclosure of information will

create an unwarranted invasion of personal privacy or provide the information required by

10 CFR 2.390(b) to support a request for withholding confidential commercial or financial

information). If safeguards information is necessary to provide an acceptable response, please

provide the level of protection described in 10 CFR 73.21.

Dated this 13th day of February, 2008

-2- ENCLOSURE 1

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 50-361, 50-362

Licenses: NPF-10, NPF-15

Report No.: 05000361/2007005 and 5000362/2007005

Licensee: Southern California Edison Co. (SCE)

Facility: San Onofre Nuclear Generating Station, Units 2 and 3

Location: 5000 S. Pacific Coast Hwy.

San Clemente, California

Dates: September 27, 2007 through December 31, 2007

Inspectors: C. C. Osterholtz, Senior Resident Inspector, Project Branch E, DRP

M. O. Miller, Senior Resident Inspector, Project Branch E, DRP

M. R. Young, Resident Inspector, Project Branch E, DRP

G. Warnick, Senior Resident Inspector, Project Branch D, DRP

R. A. Kopriva, Senior Reactor Inspector, Engineering Branch 1, DRS

J. H. Nadel, Reactor Inspector, Engineering Branch 1, DRS

G. A. George, Reactor Inspector, Engineering Branch 1, DRS

B. D. Baca, Health Physics Inspector, Plant Support Branch, DRS

L. T. Ricketson, Senior Health Physics Inspector, Plant Support

Branch, DRS

S. T. Makor, Reactor Inspector, Engineering Branch 1, DRS

J. P. Adams, Reactor Inspector, Engineering Branch 1, DRS

L. E. Ellershaw, Senior Reactor Inspector, Engineering Branch 1, DRS

M. T. Baquera, Reactor Inspector, Engineering Branch 1, DRS

K. Clayton, Senior Operations Engineer, Operations Branch, DRS

Approved By: Jeffrey A. Clark, Chief

Project Branch E

Division of Reactor Projects

-1- ENCLOSURE 2

TABLE OF CONTENTS

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -3-

REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -6-

1R02 Evaluations of Changes, Tests, or Experiments . . . . . . . . . . . . . . . . . . . . . . . -6-

1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -7-

1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -8-

1R07 Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -9-

1R11 Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -17-

1R12 Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -18-

1R13 Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . -20-

1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -20-

1R17 Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -23-

1R19 Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -23-

1R20 Refueling and Other Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -24-

1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -25-

1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -25-

1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -26-

RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -27-

2OS1 Access Control To Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . -27-

2OS2 Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -29-

OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -30-

4OA1 Performance Indicator (PI) Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . -30-

4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . -32-

4OA5 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -36-

4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -38-

4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -39-

ATTACHMENT: SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-20

-2- ENCLOSURE 2

SUMMARY OF FINDINGS

IR05000361/2007005, 05000362/2007005; 09/27/07 - 12/31/07; San Onofre Nuclear

Generating Station, Units 2 & 3; Integrated Resident and Regional Report; Emergent Work,

Operability Evaluations, Occupational Radiation Safety, Problem Identification and Resolution.

This report covered a 3-month period of inspection by resident inspectors and Regional office

inspectors. The inspection identified four Green findings consisting of one cited violation and

three noncited violations. The significance of most findings is indicated by their color (Green,

White, Yellow, or Red) using Inspection Manual Chapter 0609, "Significance Determination

Process." Findings for which the significance determination process does not apply may be

Green or be assigned a severity level after NRC management's review. The NRCs program

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

NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green. The inspectors identified a Green noncited violation of

10 CFR 50.65(a)(2) associated with the failure to include Units 2 and 3

emergency diesel generator (EDG) automatic voltage regulator (AVR)

deficiencies as functional failures in the maintenance rule program. The

inspectors noted that the voltage regulator deficiencies should have placed the

emergency diesel generators into Maintenance Rule 10 CFR 50.65(a)(1) status

approximately 6 months after the failures occurred. This caused a lapse in the

determination of appropriate system monitoring and goal setting to maintain

system reliability. This issue was entered into the licensee's corrective action

program as Action Request 070300161.

This finding was associated with the mitigating systems cornerstone. This issue

was similar to non-minor Example 7.b of Manual Chapter 0612, Appendix E, in

that the finding was more than minor since violations of 10 CFR 50.65(a)(2)

necessarily involve degraded system performance. This finding is not suitable

for evaluation using the Significance Determination Process because the

performance deficiency did not cause the degraded equipment performance.

This is a Category II finding per Inspection Procedure 71111.12, so it was

determined to have very low safety significance (Green) by management

judgement per Manual Chapter 0609, Appendix M. The cause of the finding has

a crosscutting aspect in the area of problem identification and resolution

associated with the corrective action program (P.1©) because the licensee failed

to thoroughly evaluate the cause and extent of condition of the failed emergency

diesel generator automatic voltage regulator (Section 1R12).

Green. The inspectors identified a Green noncited violation of Technical

Specification 5.5.1.1 associated with the failure to implement procedural

guidance to ensure the proper application of a submersible pump to prevent

wetting of the steam supply to the Unit 2 turbine-driven auxiliary feedwater pump.

-3- ENCLOSURE 2

If the water level were to wet the steam line insulation, it would cause

condensation in the steam line and render the auxiliary feedwater pump

inoperable due to possible water hammer or turbine overspeed on a pump start.

This issue was entered into the licensees corrective action program as Action

Request 071000309.

The finding was more than minor because it was associated with the design

control attribute of the mitigating systems cornerstone and impacted the

cornerstone objective to ensure the availability, reliability, and capability of

systems that respond to initiating events. Using Manual Chapter 0609,

Significance Determination Process, Phase 1 worksheet, the finding was

determined to have very low safety significance (Green) because it did not result

in a loss of safety function and did not affect the risk of external initiators. The

finding had a crosscutting aspect in the area of problem identification and

resolution associated with the corrective action program (P.1©) in that the

licensee did not thoroughly evaluate the problem such that the resolutions

address causes and extent of conditions (Section 1R15).

Green. A self-revealing Green violation of 10 CFR Part 50, Appendix B,

Criterion XVI, was identified for the failure to prevent recurrence of premature

tripping of Square D thermal overloads used for equipment protection on safety-

related equipment. The licensee failed to scope the thermal overloads

associated with the Unit 3 saltwater cooling pump room because they had

previously determined that it had sufficient margin such that it would not be

susceptible to failure. This resulted in the premature tripping of thermal

overloads for the Unit 3 saltwater cooling pump room intake structure fan on

August 8, 2007. This issue was entered into the licensee's corrective action

program as Action Request 070800454.

The finding was determined to be more than minor because it was associated

with the equipment performance attribute of the mitigating systems cornerstone

and it affected the cornerstone objective by challenging the availability and

capability of safety-related components. The inspectors also noted that this a

repetitive problem in implementing corrective actions. Based on the results of

the Significance Determination Process Phase 1 evaluation, the finding was

determined to have very low safety significance because it did not result in an

actual loss of a system safety function, a loss of a single train of safety

equipment for greater than its Technical Specification allowed outage time, and

did not screen as potentially risk significant due to seismic, flooding, or severe

weather initiating events. This finding also had crosscutting aspects in the area

of problem identification and resolution associated with the corrective action

program (P.1©) because the licensee failed to thoroughly evaluate the extent of

condition of insufficient solder material on safety-related thermal overloads

(Section 4OA2).

-4- ENCLOSURE 2

Cornerstone: Occupational Radiation Safety

Green. The inspector reviewed a self-revealing noncited violation of Technical

Specification 5.5.1.1 when a worker failed to follow radiation work permit

instructions. On July 14, 2007, after completing a pre-job site review, a worker

proceeded to verify work authorization boundaries in Unit 3, Room 209, without

contacting radiation protection for current radiological conditions and discussing

the work scope and locations as required by the radiation work permit. The

worker approached Valve S31902MU012 and received a dose rate alarm. The

maximum dose rate levels in the area were 30 millirem per hour on contact with

the piping system and 12 millirem per hour at 30 centimeters. The licensees

corrective actions were to coach the worker and to develop and implement a

mechanism to communicate associated boundary walk downs in maintenance

orders.

The failure to follow a radiation work permit instruction is a performance

deficiency. This finding is greater than minor because it is associated with one of

the cornerstone attributes (exposure control) and affected the Occupational

Radiation Safety cornerstone objective, in that workers not following their

radiation work permit does not ensure adequate protection of the worker health

and safety from additional personnel exposure. The finding was determined to

be of very low safety significance because it did not involve: (1) as low as is

reasonably achievable planning and controls, (2) an overexposure, (3) a

substantial potential for overexposure, or (4) an impaired ability to assess dose.

Further, this finding had a human performance crosscutting aspect in the work

practices component because the workers did not use human error prevention

techniques, such as self checking, to ensure the full work scope, locations, and

radiological conditions were discussed with radiation protection personnel as

required by the radiation work permit H4a] (Section 2OS1).

B. Licensee-Identified Violations

Violations of very low safety significance which were identified by the licensee have

been reviewed by the inspectors. Corrective actions taken or planned by the licensee

have been entered into the licensees corrective action program. These violations and

their corrective actions are listed in Section 4OA7 of this report.

-5- ENCLOSURE 2

REPORT DETAILS

Summary of Plant Status

Unit 2 began the inspection period at 99 percent power. On October 20, 2007, Unit 2 was

shutdown to Mode 3 to perform an extent of condition review as a result of Unit 3 main steam

isolation valve, main feedwater isolation valve, and main feedwater block valve solenoid

failures. The surveillance tests for Unit 2 valves that contained the specific solenoids in

question were performed when Unit 2 was in Mode 3. All surveillance tests were completed

satisfactory. Unit 2 was to restart on October 21, 2007, but did not begin restart until

October 25, 2007, due to complications with the Southern California brush fires. Unit 2

returned to power operation on October 26, 2007.

On November 26, 2007, Unit 2 was shutdown and cooled down for a planned refueling outage.

Unit 2 entered Mode 6 and began core alterations on December 7, 2007. Unit 2 was still in the

refueling outage at the end of the inspection period.

Unit 3 began the inspection period at 99.9 percent. On October 9, 2007, the licensee

performed a shutdown of Unit 3 for a planned mid-cycle outage. Unit 3 was returned to power

operation on November 9, 2007, and ended the inspection period at approximately 99.9 percent

reactor power.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

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 (UFSA) 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.

The inspectors reviewed eight safety evaluations performed by the licensee since the

last NRC inspection of this area at San Onofre Nuclear Generating Station. 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 33 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 and screenings reviewed are listed in the

attachment to this report.

The inspectors reviewed and evaluated a sample of recent licensee action requests to

determine whether the licensee had identified problems related to 10 CFR Part 50.59

-6- ENCLOSURE 2

evaluations, entered them into the corrective action program (CAP), and resolved

technical concerns and regulatory requirements. The reviewed action requests 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 eight licensee safety evaluations and

33 screenings.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors: (1) walked down portions of the three 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 walk

down to the licensee's UFSAR and CAP to ensure problems were being identified and

corrected.

October 18, 2007, Unit 3, Shutdown Cooling Train B prior to mid-loop operations

October 29, 2007, Unit 3, Train B containment spray pump (P013) used as

backup to shutdown cooling

December 18, 2007, Unit 2, electrical alignment to safety Bus 2A06 while 2A04

is out of service

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors: (1) reviewed plant procedures, drawings, the UFSAR, Technical

Specifications (TS), and vendor manuals to determine the correct alignment of the

Unit 2 auxiliary feedwater system; (2) reviewed outstanding design issues, operator

workarounds, and UFSAR documents to determine if open issues affected the

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functionality of the Unit 2 auxiliary feedwater system; and (3) verified that the licensee

was identifying and resolving equipment alignment problems. Documents reviewed by

the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

a. Inspection Scope

Quarterly Inspection

The inspectors walked down the six 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 and that access to manual actuators was

unobstructed; (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 that the compensatory measures

were commensurate with the significance of the deficiency; and (7) reviewed the UFSAR

to determine if the licensee identified and corrected fire protection problems.

C October 2, 2007, Unit 2, emergency diesel Generator (EDG) 2G002 room

C October 2, 2007, Unit 2, EDG 2G003 room

C October 2, 2007, Unit 3, EDG 3G002 room

C October 2, 2007, Unit 3, EDG 3G003 room

November 14, 2007, Unit 2, emergency core cooling system pump Room 002

December 5, 2007, Unit 2, containment

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

-8- ENCLOSURE 2

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07A)

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry

standards and reviewed critical operating parameters and maintenance records for the

Unit 3 Train B component cooling water heat Exchanger S31203ME002. The inspectors

verified that: (1) performance tests were satisfactorily conducted for heat

exchangers/heat sinks and reviewed for problems or errors; (2) the licensee utilized the

periodic maintenance method outlined in Electric Power Research Institute (EPRI)

NP- 7552, "Heat Exchanger Performance Monitoring Guidelines;" (3) the licensee

properly utilized biofouling controls; (4) the licensees heat exchanger inspections

adequately assessed the state of cleanliness of their tubes, and (5) the heat exchanger

was correctly categorized under the Maintenance Rule. Documents reviewed by the

inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities (71111.08)

.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water

Reactor Vessel Upper Head Penetration Inspections, Boric Acid Corrosion Control

a. Inspection Scope

The inspection procedure requires review of two or three types of nondestructive

examination (NDE) activities and, if performed, one to three welds on the reactor coolant

system (RCS) pressure boundary.

The inspectors directly observed the following nondestructive examinations:

System Component/Weld ID Exam Type

RCS Surge Nozzle to Safe End Weld, 02-005-031 PT/UT

RCS Shutdown Cooling Piping 10" SCH 140 PT/UT

Pipe-Valve, 02-059-008

RCS Shutdown Cooling Piping 16" SCH 160 PT/UT

Pipe-Elbow, 02-059-002

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RCS Shutdown Cooling piping 16" SCH 160 PT/UT

Pipe-Valve, 02-059-001

RCS Snubber, 02-052-110 VT3

The inspectors reviewed the following NDEs through record review:

System Component/Weld ID Exam Type

RCS Y-Stop Valve, 02-021-068 VT3

RCS Y-Stop Valve, 02-021-081 VT3

RCS Guide & Y-Stop Valve, 02-039-058 VT3

Feedwater Guide & Y-Stop Valve, 02-045-037 VT3

RCS 10" SCH 140 Reducer Tee-Pipe, 02-021-038 UT

The inspectors observed the initial Ultrasonic Examination System calibration for the

Panametrics Epoch 4 instrument, S/N 040229207, which was recorded on Ultrasonic

Instrument Calibration Data Record and Certification. The inspectors reviewed Table 1

in Electric Power Research Institute's PDI Protocol PDI-UT-2, Revision 20, dated 25

APR 07, to verify that the transducers to be used for ultrasonic examinations on

stainless steel piping were appropriately qualified.

The inspectors reviewed the NDE personnel qualification records for those contractor

personnel (Lambert MacGill Thomas, Inc. or LMT) performing ASME Code Section XI

inservice inspections. The LMT personnel had been appropriately certified using LMT's

procedure QA-46, "Qualification and Certification of NDE and Visual Examination

Personnel per ASME Section XI," Revision 0. The inspectors verified that the

requirements in QA-46 were consistent with ASNT CP-189-1995, ASNT Standard for

Qualification and Certification of Nondestructive Testing Personnel, 1995 Edition.

The inspection procedure further required verification of one to three welds on Class 1

or 2 pressure boundary piping to ensure that the welding process and welding

examinations were performed in accordance with the ASME code. The inspectors

observed portions of the preemptive structural weld overlay on the ASME code Class 1

pressurizer surge line nozzle-to-safe end dissimilar weld and pipe-to-safe end stainless

steel weld identified as follows:

System Component/Weld Identification

Pressurizer Surge Weld DMW 02-0005-031and Weld 02-016-001 Gas

Line Nozzle-to-Safe Tungsten Arc Welding (machine)

End-to-Pipe

Welding procedures and NDE of the welding repair conformed to ASME code

requirements and licensee commitments.

-10- ENCLOSURE 2

Welder qualification documentation packages and welder maintenance logs were

reviewed for all contract welders (Welding Services, Inc.) performing welding activities

on the pressurizer surge nozzle. The documentation packages and logs were in

accordance with Article III, QW-300 "Welding Performance Qualification" in Section IX

of the ASME code.

Welding Procedure Specifications WPS 08-08-T-001-Butter SS, Revision 0, and

WPS 03-08-T-804-Bottom, Revision 0, were the welding procedures observed being

used during the weld overlay process on the pressurizer surge nozzle. The inspectors

reviewed the welding procedure specifications and their corresponding procedure

qualification records (identified in the Attachment) to verify that ASME Code required

essential variables for the gas tungsten arc welding process had been identified,

recorded in the procedure qualification record, and formed the basis for qualification of

the welding procedure specifications.

Additionally, the inspectors reviewed manual gas tungsten arc welding and shielded

metal arc welding performed on an ASME Code Class 3 component cooling water

by-pass line around the letdown heat exchanger. This welding consisted of carbon steel

pipe-to-pipe and pipe-to-fitting (4" and 8") welding using ER70S-6 and E7018 welding

filler material. The reviewed welds are identified as Weld Records WR2-07-212,

WR2-07-213, and WR2-07-210.

The inspectors verified, by review, that the Welding Procedure Specification (1-GT-SM)

had been properly qualified in accordance with the requirements of Section IX of the

ASME code. The inspectors verified that the essential variables for both the shielded

metal arc welding and the gas tungsten arc welding processes had been identified,

recorded in the procedure qualification record, and formed the bases for qualification of

the welding procedure specification.

The inspectors also observed the liquid penetrant examinations performed on the buffer

(stainless steel) layer and the transition bead (between the buffer layer and the dilution

layer). The buffer layer represents the initial stainless steel layer of the weld overlay

that started at a point on the stainless steel pipe and covered the pipe, pipe-to-safe end

weld, safe end, and ending as close as practical to the dissimilar metal weld fusion line,

without contacting the dissimilar metal weld. These examinations were recorded on

Liquid Penetrant Nondestructive Examination Report 104532-PT-001. The examination

personnel qualification records for the examiner performing the examination were

reviewed to verify that the individual was properly certified. Further, the inspectors

reviewed the liquid penetrant procedure (WSI QAP 9.21, Revision 1) to verify that it was

properly qualified in accordance with ASME code Section V requirements. Additionally,

the inspectors reviewed the Ultrasonic Examination Report of the ultrasonic examination

performed on December 10, 2007, of the weld overlay which was at a nominal thickness

of 0.30 inches at the examination time.

-11- ENCLOSURE 2

The inspectors also verified by observation that welding filler materials were properly

stored and controlled in accordance with Procedure SO 123-I-11.1. Welding Filler

Material Control Records, used to document issuance and return of welding filler

materials, were reviewed for those materials issued on December 13, 2007, to verify

that specified administrative controls regarding welders, materials (quantity and time

limits), and use of portable ovens or caddys were being implemented.

The inspection procedure required inspection of any augmented or industry initiation

examinations. The inspectors determined that the licensee had not performed such

examinations. Consequently, the inspectors did not perform any activities in this area.

b. Findings

No findings of significance were identified.

.2 Vessel Upper Head Penetration (VUHP) Inspection Activities

a. Inspection Scope

The licensee performed NDEs of 100 percent of reactor VUHP. The inspector directly

observed a sample of the examinations performed on the control element drive

mechanism element (CEDM) and incore instrumentation (ICI) as listed below:

System Component/Weld Identification Examination Method

RCS CEDM 87 UT/ET

RCS CEDM 88 UT/ET

RCS CEDM 79 UT/ET

RCS CEDM 68 UT/ET

RCS CEDM 60 UT/ET

RCS CEDM 28 UT/ET

RCS CEDM 78 UT/ET

RCS CEDM 86 UT/ET

RCS ICI 96 UT/ET

RCS ICI 95 UT/ET

RCS ICI 94 UT/ET

RCS ICI 93 UT/ET

RCS RVUH vent line UT/ET

-12- ENCLOSURE 2

The NDEs were performed in accordance with the requirements of NRC Order

EA-03-009.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control Inspection (BACC) Activities

a. Inspection Scope

Resident inspectors observed a sample of BACC activities and verified that visual

inspections emphasized locations where boric acid leaks can cause degradation of

safety significant components.

The inspector reviewed five instances where boric acid deposits were found on reactor

coolant system piping components during the walkdown. The inspectors reviewed

licensee procedures governing the boric acid corrosion control program and inspector

qualifications, reviewed the extent of boric acid residue on the various components,

verified that the licensee inspectors who performed the walkdown were qualified, and

determined whether components that exhibited leakage during the current outage had

experienced leakage in the past. The following table lists the specific components

reviewed by the inspector, including the component numbers, brief component

descriptions, and the resulting Action Requests.

Component Number Description Action Request

2HV0512 Pressurizer surge line sample 070500261

isolation valve

2HV9203 Charging line insolation valve 071101172

2HV9201 Charging auxiliary spray 071101173

isolation valve

2HV9339 Shutdown cooling isolation 070500262

valve

2HV9326 Shutdown injection tank drain 070500265

valve

No boric acid leakage evaluations were performed for any of the instances where leaks

were identified during walkdowns.

The condition of the components was appropriately entered into the licensee's CAP and

corrective actions taken were consistent with ASME code requirements. No engineering

evaluations were required for any of the instances where leaks were identified during

walkdowns.

-13- ENCLOSURE 2

b. Findings

No findings of significance were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The inspection procedure specified performance of an assessment of in-situ screening

criteria to assure consistency between assumed NDE flaw sizing accuracy and data

from the EPRI examination technique specification sheets. It further specified

assessment of appropriateness of tubes selected for in situ pressure testing,

observation of in situ pressure testing, and review of in situ pressure test results.

At the time of this inspection, no conditions had been identified that warranted in situ

pressure testing. The inspectors did, however, review the licensee's report for Units 2

and 3, Steam Generator Degradation Assessment for the Cycle 15 Refueling Outages

in 2007 and 2008, dated November 29, 2007, and compared the in situ test screening

parameters to the guidelines contained in the EPRI document In Situ Pressure Test

Guidelines, Revision 2, and the Combustion Engineering Owners Group screening

criteria. This review determined that the remaining screening parameters were

consistent with the EPRI and Combustion Engineering Owners Group guidelines.

In addition, the inspectors reviewed both the licensee site-validated and qualified

acquisition and analysis technique sheets used during this refueling outage and the

qualifying EPRI examination technique specification sheets to verify that the essential

variables regarding flaw sizing accuracy, tubing, equipment, technique, and analysis had

been identified and qualified through demonstration. The inspector reviewed acquisition

technique and analysis technique sheets are identified in the attachment.

The inspection procedure specified comparing the estimated size and number of tube

flaws detected during the current outage against the previous outage operational

assessment predictions to assess the licensee's prediction capability. The inspectors

compared the previous outage operational assessment predictions contained in

Report R-3671-00-1, Tube Degradation Predictions for the San Onofre Nuclear

Generating Station Unit 2 Steam Generators - 2006 Update, with the flaws identified

thus far during the current steam generator tube inspection effort. Compared to the

projected damage mechanisms identified by the licensee, the number of identified

indications fell within the range of prediction and were quite consistent with predictions.

No new damage mechanisms had been identified during this inspection.

The inspection procedure specified confirmation that the steam generator tube eddy

current test scope and expansion criteria meet TS requirements, EPRI guidelines, and

commitments made to the NRC. The inspectors evaluated the recommended steam

generator tube eddy current test scope established by TS requirements and the

licensees degradation assessment report. The inspectors compared the recommended

test scope to the actual test scope and found that the licensee had accounted for all

known flaws and had, as a minimum, established a test scope that met TS

-14- ENCLOSURE 2

requirements, EPRI guidelines, and commitments made to the NRC. The scope of the

licensee's eddy current examinations of tubes in both steam generators included:

Bobbin examination full length of tubing (tube end hot-tube end cold) from both

hot and cold legs, in non-sleeved tubes, rows 4-147

Bobbin examination of the unsleeved portion of tubing (sleeve top hot-tube end

cold) from the cold leg, in sleeved tubes, rows 4-147

Bobbin examination of the straight length section of tubing from both hot and

cold legs, rows 1-3

Rotating plug point coil examination of hot leg Tubsheet TSH +4", -13",

100 percent of all tubes

Rotating plug point coil examination of cold leg tubesheet, TSC +2", -13",

100 percent of all tubes. Exception: Steam Generator 89 tubes R141-C63,

R140-C64, R139-C63, and surrounding tubes in 2-tube bounding pattern,

examination extent is TSC +4", -13".

Rotating plug point coil examination of the sleeves (sleeve bottom hot-sleeve top

hot), 100 percent of sleeved tubes

Rotating plug point coil examination of SBF 0.00", -1.25" in Steam Generator 88,

Tube R28-C60 only

Rotating plug point coil examination of U-bend section of tubing (07H-07C) with

mid/high frequency coil probe, 100 percent of tubes in rows 1-3

Rotating plug point coil examination of U-bend section of tubing (07H-07C) with

mid-frequency coil probe, 20 percent sample of tubes in rows 4-10 (rows 5-10

sample drawn from tubes not examined with MRPC probe in the 2006

inspection)

Rotating plug point coil examination of the following bobbin indications: ADR,

DNI, DEI,DSI, DTI, LPI, PLP, NQI, TWD (0-100 percent), DNT >= 2.0 volts, DNG

>= 4.0 volts, TSD, TSM, PDP, and CUD

Rotating plug point coil examination of PLP indications (with LAR confirmation) in

a 2-tube bounding pattern, location +/- 1-inch of PLP edges

Rotating plug point coil examination of all sections of tubing which cannot be

examined with the 600UL bobbin probe due to restriction

The inspection procedure specified, if new degradation mechanisms were identified,

verify that the licensee fully enveloped the problem in its analysis of extended conditions

including operating concerns and had taken appropriate corrective actions before plant

startup. To date, the eddy current test results had not identified any new degradation

mechanisms.

-15- ENCLOSURE 2

The inspection procedure requires confirmation that the licensee inspected all areas of

potential degradation, especially areas that were known to represent potential eddy

current test challenges (e.g., top-of-tubesheet, tube support plates, and U-bends). The

inspectors confirmed that all known areas of potential degradation were included in the

scope of inspection and were being inspected.

The inspection procedure further requires verification that repair processes being used

were approved in the TSs. The total number of tubes plugged was 133 tubes in Steam

Generator 88 and 125 tubes in Steam Generator 89. The inspectors verified that the

mechanical expansion plugging process to be used was an NRC-approved repair

process.

The inspection procedure also requires confirmation of adherence to the TS plugging

limit, unless alternate repair criteria have been approved. The inspection procedure

further requires determination whether depth sizing repair criteria were being applied for

indications other than wear or axial primary water stress corrosion cracking in dented

tube support plate intersections. The inspectors determined that the TS plugging limits

were being adhered to (i.e., 40 percent maximum through-wall indication).

If steam generator leakage greater than three gallons per day was identified during

operations or during post shutdown visual inspections of the tubesheet face, the

inspection procedure requires verification that the licensee had identified a reasonable

cause based on inspection results and that corrective actions were taken or planned to

address the cause for the leakage. The inspectors did not conduct any assessment

because this condition did not exist.

The inspection procedure requires confirmation that the eddy current test probes and

equipment were qualified for the expected types of tube degradation and an assessment

of the site-specific qualification of one or more techniques. The inspectors observed

portions of eddy current tests performed on the tubes in Steam Generators 88 and 89.

During these examinations, the inspectors verified that: (1) the probes appropriate for

identifying the expected types of indications were being used, (2) probe position location

verification was performed, (3) calibration requirements were adhered, and (4) probe

travel speed was in accordance with procedural requirements. The inspectors

performed a review of site-specific qualifications of the techniques being used. These

are identified in the attachment.

If loose parts or foreign material on the secondary side were identified, the inspection

procedure specified confirmation that the licensee had taken or planned appropriate

repairs of affected steam generator tubes and that they inspected the secondary side to

either remove the accessible foreign objects or perform an evaluation of the potential

effects of inaccessible object migration and tube fretting damage. At this time of the

inspection, no foreign material had been identified.

Finally, the inspection procedure specified review of one to five samples of eddy current

test data if questions arose regarding the adequacy of eddy current test data analyses.

The inspectors did not identify any results where eddy current test data analyses

adequacy was questionable.

-16- ENCLOSURE 2

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspection procedure requires review of a sample of problems associated with

inservice inspections documented by the licensee in the corrective action program for

appropriateness of the corrective actions.

The inspector reviewed corrective action reports which dealt with inservice inspection

activities and found the corrective actions were appropriate. Action requests reviewed

are listed in the documents reviewed section. From this review the inspectors

concluded that the licensee has an appropriate threshold for entering issues into the

corrective action program and has procedures that direct a root cause evaluation when

necessary. The licensee also has an effective program for applying industry operating

experience.

b. Findings

No findings of significance were identified. The inspectors completed one sample by

completing all required inspection activities.

1R11 Licensed Operator Requalification (71111.11)

.1 Quarterly Inspection

a. Inspection Scope

The inspectors observed testing and training of senior reactor operators and reactor

operators to identify deficiencies and discrepancies in the training, to assess operator

performance, and to assess the evaluator's critique. The training scenario on

October 22, 2007, involved just-in-time training for Unit 2 startup. Documents reviewed

by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.2 Annual Inspection

a. Inspection Scope

The inspectors reviewed the annual operating examination test results for 2007. Since

this was the first half of the biennial requalification cycle, the licensee was not required

-17- ENCLOSURE 2

to administer a written examination. These results were assessed to determine if they

were consistent with NUREG 1021, Operator Licensing Examination Standards for

Power Reactors, guidance and Manual Chapter 0609, Appendix I, Operator

Requalification Human Performance Significance Determination Process,

requirements. This review included the test results for a total of 15 crews composed of

87 licensed operators, which included: shift-standing senior operators, staff senior

operators, shift-standing reactor operators, and staff reactor operators. There were no

crew failures and no individual failures on the simulator scenario portion of the test.

There was one individual failure on the job performance measure portion of the test.

This individual was successfully remediated prior to returning to shift.

The inspector completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors reviewed the listed maintenance activity to: (1) verify the appropriate

handling of SSC performance or condition problems; (2) verify the appropriate handling

of degraded SSC functional performance; (3) evaluate the role of work practices and

common cause problems; and (4) evaluate the handling of SSC issues reviewed under

the requirements of the maintenance rule, 10 CFR Part 50 Appendix B, and the TSs.

October 1, 2007, Units 2 and 3, upgraded EDG automatic voltage regulators

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

Introduction. The inspectors identified a Green NCV of 10 CFR 50.65(a)(2) for the

failure to include Units 2 and 3 EDG automatic voltage regulator (AVR) deficiencies as

functional failures in the maintenance rule program. The inspectors noted that the

voltage regulator deficiencies should have placed the EDGs into maintenance rule

10 CFR 50.65(a)(1) status approximately six months after the failures occurred. This

caused a lapse in the determination of appropriate system monitoring and goal setting to

maintain system reliability.

Description. On March 3, 2007, the licensee identified that an AVR for the Unit 3 EDG

was oscillating excessively during a load test. The cause of the oscillation was poor

contact of the R3 potentiometer because of the open type housing of the potentiometers

which made them susceptible to dirt intrusion.

-18- ENCLOSURE 2

The licensees analysis of the failed AVR concluded that the R3 potentiometer poor

contact caused the AVR to oscillate the EDG output voltage setting between zero and

3.8 megavolt ampere reactive (MVAR). Operations personnel subsequently declared

the EDG inoperable. All of the susceptible potentiometers on all eight EDGs were

subsequently upgraded to sealed multiturn gold plated potentiometers. The upgraded

installations were completed on August 26, 2007.

The inspectors discovered that the licensee had not evaluated the AVR deficiency in

their maintenance rule program for monitoring or goal setting. The inspectors

determined that the AVR failure impacted the reliability of the EDGs in accordance with

NUMARC 93-01, Nuclear Energy Institute Industry Guideline for Monitoring the

Effectiveness of Maintenance of Nuclear Power Plants, Revision 2. The inspectors

concluded that the AVR failure if correctly counted as a MPFF, would have caused the

EDG to exceed the performance criteria and should have been tracked for monitoring

and goal setting in the licensees maintenance rule program. In response to this finding,

the licensee subsequently placed the EDGs in 10 CFR 50.65(a)(1), and established an

EDG performance goal such that both Unit 2 and 3 EDG AVRs be successfully

surveillance tested four times each, with normal voltage and MVAR control, by the end

of the fourth quarter of 2007. Each EDG contains an AVRs A and B, therefore four

diesels each containing two AVRs would need to be surveillance tested four times to

successfully complete the goal.

Analysis. The failure to recognize the applicability of the maintenance rule for a failure

of the EDG AVR was a performance deficiency. This finding was associated with the

mitigating systems cornerstone. This issue was similar to non-minor Example 7.b of

Manual Chapter 0612, Appendix E, in that the finding was more than minor since

violations of 10 CFR 50.65(a)(2) necessarily involve degraded system performance.

This finding is not suitable for evaluation using the Significance Determination Process

because the performance deficiency did not cause the degraded equipment

performance. This is a Category II finding per Inspection Procedure 71111.12, so it was

determined to have very low safety significance (Green) by management judgement per

Manual Chapter 0609, Appendix M. The cause of the finding has a crosscutting aspect

in the area of problem identification and resolution associated with the CAP (P.1(c))

because the licensee failed to thoroughly evaluate the cause and extent of condition of

the failed EDG AVR.

Enforcement. 10 CFR Part 50.65(a)(1) requires, in part, that holders of an operating

license shall monitor the performance or condition of SSCs within the scope of the rule

against licensee-established goals in a manner sufficient to provide reasonable

assurance that such SSCs are capable of fulfilling their intended safety functions.

10 CFR 50.65(a)(2) requires, in part, that monitoring specified in paragraph (a)(1) is not

required where it has been demonstrated the performance or condition of an SSC is

being effectively controlled through appropriate preventive maintenance, such that the

SSC remains capable of performing its intended function. Contrary to the above, from

March through September, 2007, the licensee failed to demonstrate the performance of

the EDGs was being effectively controlled through appropriate preventive maintenance

and did not establish goals to provide a reasonable assurance that the Units 2 and 3

EDGs were capable of fulfilling their intended function. Because the finding is of very

low safety significance and has been entered into the licensees CAP as AR 070300161,

-19- ENCLOSURE 2

this violation is being treated as an NCV consistent with Section VI.A of the Enforcement

Policy: NCV 05000361;05000362/2007005-01, Failure to Properly Implement

Maintenance Rule Requirements for Emergency Diesel Generators.

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

.1 Risk Assessment and Management of Risk

a. Inspection Scope

The inspectors reviewed the four below listed assessment activities to verify:

(1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and

licensee procedures prior to changes in plant configuration for maintenance activities

and plant operations; (2) the accuracy, adequacy, and completeness of the information

considered in the risk assessment; (3) that the licensee recognizes, and/or enters as

applicable, the appropriate licensee-established risk category according to the risk

assessment results and licensee procedures; and (4) the licensee identified and

corrected problems related to maintenance risk assessments.

October 4, 2007, Unit 3, risk assessment and management during an unplanned

emergency core cooling system TS 3.0.3 entry

October 25, 2007, Unit 2, risk assessment and management during a startup

after unplanned shutdown and southern California fires

October 12, 2007, Unit 3, risk assessment and management during a main

steam isolation valve dual indication

November 30, 2007, Unit 2, risk assessment and management during the

Devers offsite power out of service - delayed midloop operations

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors: (1) reviewed plants 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 UFSAR 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

-20- ENCLOSURE 2

any TSs; (5) used the Significance Determination Process to evaluate the risk

significance of degraded or inoperable equipment; and (6) verified that the licensee has

identified and implemented appropriate corrective actions associated with degraded

components.

October 3, 2007, Units 2 and 3, incorrect calibration probe used for saltwater

cooling flow indicators

October 4, 2007, Unit 2 turbine-driven auxiliary feedwater pump failed trench

eductor

October 9, 2007, Unit 3, grounded pressurizer heater

October 25, 2007, Unit 2 and 3, main feedwater isolation Valve 2HV4048 and

main steam isolation Valve 2HV8204 solenoid failed in-service testing

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b. Findings

Introduction. The inspectors identified a Green NCV of TS 5.5.1.1 associated with the

failure to implement procedural guidance to ensure the proper application of a

submersible pump to prevent wetting of the steam supply to the Unit 2 turbine-driven

auxiliary feedwater pump. If the water level were to wet the steam line insulation, it

would cause condensation in the steam line and render the auxiliary feedwater pump

inoperable due to possible water hammer or turbine overspeed on a pump start.

Description. On October 4, 2007, during a plant walk-down, the inspectors noted that a

submersible pump was in use in a pipe trench in the Unit 2 auxiliary feedwater (AFW)

pump building while steam was discharging into the bottom of the pipe trench. The

pump was a temporary modification installed due to a failure of a permanently installed

eductor. The purpose of the eductor was to ensure water did not accumulate in the

trench such that it could contact the steam piping. If the water level were to wet the

steam line insulation, it would cause condensation in the steam line and render the

turbine-driven AFW pump inoperable due to the possibility of water hammer or

overspeed on turbine start.

The inspectors noted that the atmosphere in the top of the pipe trench felt very hot to

the touch. The inspectors then reviewed the vendor manual for the submersible pump

and hose and found that both had a maximum temperature rating of 140EF. The

inspectors concluded that water in the pipe trench could easily exceed the maximum

temperature rating for the submersible pump and hose rated of 140EF. Since this

temperature would exceed the rating of the pump and hose, the submersible pump

modification could not be relied upon to drain the trench. This could potentially render

the turbine driven AFW pump inoperable.

-21- ENCLOSURE 2

The inspectors interviewed the licensees staff and found that the submersible pump

and discharge hose had been installed per Procedure S023-2-16, Use of Temporary

Sump Pumps, Revision 20. The inspectors noted this procedure did not direct

consideration of the environment in which the pump would be used or the potential

consequences of failure of the pump, as would have been required by

Procedure S0123-XV-5.1, Temporary Modifications Control, Revision 8. Since the

failure of the submersible pump had the potential consequence of rendering safety-

related equipment inoperable, the inspectors concluded the procedure used to install the

modification was inadequate.

Corrective actions taken by the licensee included revising the Use of Temporary Sump

procedure to reflect the guidance found in the Temporary Modifications Control

procedure for consideration of the environmental effects on the submersible pump.

Additionally, the licensee revised Procedure OSM-5, Operator Rounds, Revision 7, and

replaced the submersible pump with one that was adequately temperature rated for the

environment in the AFW trench.

Analysis. The failure to have an adequate procedure resulting in an inadequate

modification with the potential to affect safety-related equipment was a performance

deficiency. The finding was more than minor because it was associated with the design

control attribute of the mitigating systems cornerstone and impacted the cornerstone

objective to ensure the availability, reliability, and capability of systems that respond to

initiating events. Using Manual Chapter 0609, Significance Determination Process,

Phase 1 worksheet, the finding was determined to have very low safety significance

(Green) because it did not result in a loss of safety function and did not affect the risk of

external initiators. The finding had a crosscutting aspect in the area of problem

identification and resolution associated with the CAP (P.1(c)) in that the licensee did not

thoroughly evaluate the problem such that such that the resolutions address causes and

extent of conditions.

Enforcement. TS 5.5.1.1 requires that written procedures be established, implemented,

and maintained for activities specified in Appendix A, Typical Procedures for

Pressurized Water Reactors and Boiling Water Reactors, of Regulatory Guide 1.33,

Quality Assurance Program Requirements (Operations), dated February 1978.

Regulatory Guide 1.33, Appendix A, Section 9.e recommends general procedures for

the control of maintenance and modification work. Contrary to this requirement, on

May 11, 2007, the licensee failed to implement appropriate procedures to control

modification work in the Unit 2 auxiliary feedwater steam supply trench to ensure the

trench would not fill up with water and render the Unit 2 turbine driven auxiliary

feedwater pump inoperable. Because this violation is of very low safety significance and

has been entered into the licensees CAP as AR 071000309, it is being treated as an

NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000362/2007005-02, Failure to Implement Procedural Requirements for

Modifications in the Auxiliary Feedwater Steam Supply Trench.

-22- ENCLOSURE 2

1R17 Permanent Plant Modifications (71111.17B)

a. Inspection Scope

The inspectors reviewed seven permanent plant modification packages and associated

documentation, such as implementation reviews, safety evaluation applicability

determinations, and screenings, to verify that they were performed in accordance with

regulatory requirements and plant procedures. The inspectors also reviewed the

procedures governing plant modifications to evaluate the effectiveness of the program

for implementing modifications to risk-significant SSCs, such that these changes did not

adversely affect the design and licensing basis of the facility.

Procedures and permanent plant modifications reviewed are listed in the attachment to

this report. Further, the inspectors interviewed the cognizant design and system

engineers for the identified modifications as to their understanding of the modification

packages and process.

The inspectors evaluated the effectiveness of the licensees corrective action process to

identify and correct problems concerning the performance of permanent plant

modifications by reviewing a sample of related condition reports. The reviewed

condition reports are identified in the attachment.

The inspection procedure specifies inspectors review a required minimum sample of six

permanent plant modifications. The inspectors completed review of seven permanent

plant modifications.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors selected the six listed postmaintenance test activities of risk significant

systems or components. For each item, the inspectors: (1) reviewed the applicable

licensing basis and/or design-basis documents to determine the safety functions;

(2) evaluated the safety functions that may have been affected by the maintenance

activity; and (3) reviewed the test procedure to ensure it adequately tested the safety

function that may have been affected. The inspectors either witnessed or reviewed test

data to verify that acceptance criteria were met, plant impacts were evaluated, test

equipment was calibrated, procedures were followed, jumpers were properly controlled,

the test data results were complete and accurate, the test equipment was removed, the

system was properly re-aligned, and deficiencies during testing were documented. The

inspectors also reviewed the UFSAR to determine if the licensee identified and

corrected problems related to post maintenance testing.

October 25, 2007, Unit 2, main steam isolation Valve 2HV8204, Train A & B, fail

safe closure postmaintenance test

-23- ENCLOSURE 2

October 25, 2007, Unit 2, Main Feedwater Isolation Valve, 2HV-4048, stroke and

fail safe closure postmaintenance test

October 29, 2007, Unit 3, Pressurizer Surge Line Nozzle Field Weld OVL-031,

post weld overlay liquid penetrant postmaintenance test

October 31, 2007, Unit 3, reactor coolant gas vent system postmaintenance test

November 3, 2007, Unit 3 reactor coolant gas vent system postmaintenance test

following corrective maintenance

November 8, 2007, Unit 3, saltwater cooling Pump 3P112 postmaintenance test

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities (71111.20)

a. Inspection Scope

The inspectors reviewed the following risk significant refueling items or outage activities

to verify defense in depth commensurate with the outage risk control plan, compliance

with the TSs, and adherence to commitments in response to Generic Letter 88-17, Loss

of Decay Heat Removal: (1) the risk control plan; (2) tagging/clearance activities;

(3) reactor coolant system instrumentation; (4) electrical power; (5) decay heat removal;

(6) spent fuel pool cooling; (7) inventory control; (8) reactivity control; (9) containment

closure; (10) reduced inventory or midloop conditions; (11) refueling activities;

(12) heatup and coldown activities; (13) restart activities; and (14) licensee identification

and implementation of appropriate corrective actions associated with refueling and

outage activities. The inspectors' containment inspections included observations of the

containment sump for damage and debris; and observation of supports, braces, and

snubbers for evidence of excessive stress, water hammer, or aging. Documents

reviewed by the inspectors are listed in the attachment. The inspectors reviewed outage

activities for Unit 3 from October 9, 2007 to November 9, 2007. The inspectors also

reviewed outage activities for Unit 2 from November 26, 2007, until the end of the

inspection period.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

-24- ENCLOSURE 2

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure that

the four listed surveillance activities demonstrated that the SSCs tested were capable of

performing their intended safety functions. The inspectors either witnessed or reviewed

test data to verify that the following significant surveillance test attributes were

adequate: (1) preconditioning; (2) evaluation of testing impact on the plant;

(3) acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead

controls; (7) test data; (8) testing frequency and method demonstrated TS operability;

(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of ASME

Code requirements; (12) updating of performance indicator data; (13) engineering

evaluations, root causes, and bases for returning tested SSCs not meeting the test

acceptance criteria were correct; (14) reference setting data; and (15) annunciators and

alarms setpoints. The inspectors also verified that the licensee identified and

implemented any needed corrective actions associated with the surveillance testing.

August 1, 2007, Unit 2, 2HV-9900 normal chilled water to containment isolation

Valve 2HV-9900 stroke test

October 4, 2007, Unit 3, Train A saltwater cooling outlet Valve 3HV6497 partial

manual stroke test

October 18, 2007, Unit 2, high pressure safety injection Pump 2MP018 response

time testing

October 18, 2007, Unit 2, component cooling water Pump 2MP024 inservice test

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications (71111.23)

a. Inspection Scope

The inspectors reviewed the UFSAR, plant drawings, procedure requirements, and TSs

to ensure that the below listed temporary modification was properly implemented. The

inspectors: (1) verified that the modifications did not have an affect on system

operability/availability; (2) verified that the installation was consistent with modification

documents; (3) ensured that the post-installation test results were satisfactory and that

the impact of the temporary modifications on permanently installed SSCs were

supported by the test; and (4) verified that appropriate safety evaluations were

-25- ENCLOSURE 2

completed. The inspectors verified that licensee identified and implemented any needed

corrective actions associated with temporary modifications.

October 9, 2007, Unit 3, swap grounded pressurizer Heater ME616 with

Heater E614

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance was identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation (71114.06)

a. Inspection Scope

For the listed drill and simulator-based training evolutions contributing to Drill/Exercise

Performance and Emergency Response Organization Performance Indicators, the

inspectors: (1) observed the training evolution to identify any weaknesses and

deficiencies in classification, notification, and Protective Action Recommendation

development activities; (2) compared the identified weaknesses and deficiencies against

licensee identified findings to determine whether the licensee is properly identifying

failures; and (3) determined whether licensee performance is in accordance with the

guidance of the NEI 99-02, "Voluntary Submission of Performance Indicator Data,"

acceptance criteria.

October 3, 2007, Units 2 and 3 simulator, control room, technical support center,

operations support center, and emergency operations facility, Unit 3 diesel

Generator 3G003 fuel oil day tank fire, Unit 2 steam generator tube leak and

subsequent tube rupture with potential unfiltered radioactive release pathway

through the steam driven auxiliary feed Pump P-140 turbine exhaust

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

-26- ENCLOSURE 2

2. RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control To Radiologically Significant Areas (71121.01)

a. Inspection Scope

This area was inspected to assess the licensees performance in implementing physical

and administrative controls for airborne radioactivity areas, radiation areas, high

radiation areas, and worker adherence to these controls. The inspector used the

requirements in 10 CFR Part 20, the technical specifications, and the licensees

procedures required by technical specifications as criteria for determining compliance.

During the inspection, the inspector interviewed the radiation protection manager,

radiation protection supervisors, and radiation workers. The inspector performed

independent radiation dose rate measurements and reviewed the following items:

Performance indicator events and associated documentation packages reported

by the licensee in the Occupational Radiation Safety Cornerstone

Controls (surveys, posting, and barricades) of radiation, high radiation, or

airborne radioactivity areas in the Auxiliary, Radwaste, Reactor, and

Containment Buildings

Radiation exposure permits, procedures, engineering controls, and air sampler

locations

Conformity of electronic personal dosimeter alarm set points with survey

indications and plant policy; workers knowledge of required actions when their

electronic personnel dosimeter noticeably malfunctions or alarms

Barrier integrity and performance of engineering controls in two potential

airborne radioactivity areas

Adequacy of the licensees internal dose assessment for any actual internal

exposure greater than 50 millirem committed effective dose equivalent

Physical and programmatic controls for highly activated or contaminated

materials (non-fuel) stored within spent fuel and other storage pools.

Self-assessments, audits, licensee event reports, and special reports related to

the access control program since the last inspection

Corrective action documents related to access controls

Licensee actions in cases of repetitive deficiencies or significant individual

deficiencies

Radiation exposure permit briefings and worker instructions

-27- ENCLOSURE 2

Adequacy of radiological controls, such as required surveys, radiation protection

job coverage, and contamination control during job performance

Dosimetry placement in high radiation work areas with significant dose rate

gradients

Changes in licensee procedural controls of high dose rate - high radiation areas

and very high radiation areas

Controls for special areas that have the potential to become very high radiation

areas during certain plant operations

Posting and locking of entrances to all accessible high dose rate - high radiation

areas and very high radiation areas

Radiation worker and radiation protection technician performance with respect to

radiation protection work requirements

The inspector completed 21 of the required 21 samples.

b. Findings

Introduction. The inspector reviewed a self-revealing NCV of TS 5.5.1.1 when a worker

failed to follow radiation work permit instructions.

Description. On July 14, 2007, a worker notified health physics of a pre-job site review

prior to starting work on Valve 3HV7261 in the Post Accident Sampling System Lab. The

worker was informed of the radiological conditions for the work area. However, after

completing the pre-job site review, the worker proceeded to verify the work authorization

boundaries in Unit 3, Room 209. The worker approached Valve S31902MU012 and

received a dose rate alarm. The worker exited the radiologically controlled area and

informed health physics of the alarm. The peak dose rate received by the worker was

11.1 millirem per hour and area around valve S31902MU012 had a maximum dose rate

level of 30 millirem per hour on contact with the piping system and 12 millirem per hour at

30 centimeters. During the licensees investigation of the dose rate alarm, the licensee

determined that the worker did not inform health physics of all areas needing access to

complete the work scope and did not receive a radiological briefing for Unit 3, Room 209.

The licensees corrective actions were to coach the worker and to develop and

implement a mechanism for communicating associated boundary walk downs in

maintenance orders.

Analysis. The failure to follow a radiation work permit instruction is a performance

deficiency. This finding is greater than minor because it is associated with one of the

cornerstone attributes (exposure control) and affected the Occupational Radiation Safety

cornerstone objective, in that workers not following their radiation work permit does not

ensure adequate protection of the worker health and safety from additional personnel

exposure. This occurrence involved a workers unplanned, unintended dose, or potential

for such a dose that could have been significantly greater as a result of a single minor,

-28- ENCLOSURE 2

reasonable alteration of the circumstances, higher dose rate levels. This finding was

determined to be of very low safety significance because it did not involve: (1) as low as

is reasonably achievable (ALARA) planning and controls, (2) an overexposure, (3) a

substantial potential for overexposure, or (4) an impaired ability to assess dose. Further,

this finding has a work practices human performance cross cutting aspect in human error

prevention techniques because the worker failed to self check the work scope and work

locations when briefing with health physics prior to entering the radiological controlled

area H4a].

Enforcement. Technical Specification 5.5.1.1.a requires applicable procedures

recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Section 7(e), of the Appendix, requires procedures for access control and a radiation

work permit system. Procedure SO 123-VII-20, Health Physics Program, Revision 12,

Section 6.10.6.5 states, in part, that individuals entering a radiological controlled area

sign on an appropriate radiation exposure permit acknowledging that they agree to

comply with the radiological controls specified on the radiation exposure permit.

Radiation Exposure Permit 07070562000/200159, states, in part, that workers, prior to

entering the radiologically controlled area, are to inform the Health Physics Control Point

of the job scope and work locations. Contrary to the Radiation Exposure Permit

requirement, on July 14, 2007, the worker did not inform the health physicist at the

control point of the full work scope and work locations prior to entering the radiological

controlled area which resulted in the worker knowing the current radiological conditions of

Room 209. Because this finding is of very low safety significance and was entered into

the licensees corrective action program (Action Request 070700545), this violation is

being treated as a noncited violation in accordance with Section VI.A.1 of the

Enforcement Policy: NCV 05000362/2007005-03, Failure to follow a radiation exposure

permit requirement.

2OS2 Planning and Controls (71121.02)

a. Inspection Scope

The inspector assessed licensee performance with respect to maintaining individual and

collective radiation exposures ALARA. The inspector used the requirements in 10 CFR

Part 20 and the licensees procedures required by technical specifications as criteria for

determining compliance. The inspector interviewed licensee personnel and reviewed:

Site-specific ALARA procedures

Interfaces between operations, radiation protection, maintenance, maintenance

planning, scheduling and engineering groups

Integration of ALARA requirements into work procedure and radiation work permit

(or radiation exposure permit) documents

Dose rate reduction activities in work planning

Exposure tracking system

-29- ENCLOSURE 2

Use of engineering controls to achieve dose reductions and dose reduction

benefits afforded by shielding

Workers use of the low dose waiting areas

First-line job supervisors contribution to ensuring work activities are conducted in

a dose efficient manner

Radiation worker and radiation protection technician performance during work

activities in radiation areas, airborne radioactivity areas, or high radiation areas

Self-assessments, audits, and special reports related to the ALARA program

since the last inspection

Resolution through the corrective action process of problems identified through

post-job reviews and post-outage ALARA report critiques

Corrective action documents related to the ALARA program and follow-up

activities, such as initial problem identification, characterization, and tracking

Effectiveness of self-assessment activities with respect to identifying and

addressing repetitive deficiencies or significant individual deficiencies

The inspector completed 5 of the required 15 samples and 8 of the optional samples.

b. Findings

No findings of significance were identified.

4. OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification (71151)

a. Inspection Scope

Cornerstone: Mitigating Systems

The inspectors sampled licensee data for the Mitigating System Performance

Index (MSPI) performance indicators (PI) listed below for Units 2 and 3 for the period

from September 26, 2007 through December 31, 2007. The definitions and guidance of

Nuclear Energy Institute 99-02, "Regulatory Assessment Performance Indicator

Guideline," Revision 4, were used to verify the licensees basis for reporting unavailability

and unreliability in order to verify the accuracy of PI data. The inspectors reviewed

operating logs, Limiting Conditions for Operation logs, ARs, and the maintenance rule

database to verify that the licensee properly accounted for planned and unplanned

unavailability as part of the assessment. The inspectors sampled data to verify that the

licensee: (1) accurately documented the actual unavailability hours for the MSPI systems;

and (2) accurately documented the actual unreliability information for each MSPI

-30- ENCLOSURE 2

monitored component. In addition, the inspectors interviewed licensee personnel

associated with PI data collection and evaluation.

Units 2 and 3, safety system functional failures

The inspectors completed two samples.

Cornerstone: Barrier Integrity

The inspectors sampled licensee submittals for the four performance indicators listed

below for the period September 26, 2007 through December 31, 2007, for Units 2 and 3.

The definitions and guidance of Nuclear Energy Institute 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 4, were used to verify the licensees basis for

reporting each data element in order to verify the accuracy of PI data reported during the

assessment period. The inspectors: (1) reviewed RCS chemistry sample analyses for

dose equivalent Iodine-131 and compared the results to the TS limit; (2) observed a

chemistry technician obtain and analyze a RCS sample; (3) reviewed operating logs and

surveillance results for measurements of RCS identified leakage; and (4) observed a

surveillance test that determined RCS identified leakage. Licensee performance

indicator data were also reviewed for the following:

C Units 2 and 3, reactor coolant system specific activity

C Units 2 and 3, reactor coolant system leakage

The inspectors completed four samples.

Cornerstone : Occupational Radiation Safety

Occupational Exposure Control Effectiveness

The inspector reviewed licensee documents from January 1 through

September 30, 2007. The review included corrective action documentation that identified

occurrences in locked high radiation areas (as defined in the licensees technical

specifications), very high radiation areas (as defined in 10 CFR 20.1003), and unplanned

personnel exposures (as defined in Nuclear Energy Institute (NEI) 99-02, Regulatory

Assessment Indicator Guideline, Revision 5). Additional records reviewed included

ALARA records and whole body counts of selected individual exposures. The inspector

interviewed licensee personnel that were accountable for collecting and evaluating the

performance indicator data. In addition, the inspector toured plant areas to verify that

high radiation, locked high radiation, and very high radiation areas were properly

controlled. Performance indicator definitions and guidance contained in NEI 99-02,

Revision 5, were used to verify the basis in reporting for each data element.

The inspector completed the required sample (1) in this cornerstone.

Cornerstone: Public Radiation Safety

Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

-31- ENCLOSURE 2

The inspector reviewed licensee documents from January 1 through

September 30, 2007. Licensee records reviewed included corrective action

documentation that identified occurrences for liquid or gaseous effluent releases that

exceeded performance indicator thresholds and those reported to the NRC. The

inspector interviewed licensee personnel that were accountable for collecting and

evaluating the performance indicator data. Performance indicator definitions and

guidance contained in NEI 99-02, Revision 5, were used to verify the basis in reporting

for each data element.

The inspector completed the required sample (1) in this cornerstone.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

.1 Radiological Controls Review

a. Inspection Scope

The inspector evaluated the effectiveness of the licensees problem identification and

resolution process with respect to the following inspection areas:

Access Control to Radiologically Significant Areas (Section 2OS1)

ALARA Planning and Controls (Section 2OS2)

b. Findings

No findings of significance were identified.

.2 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a daily screening of items entered into the licensee's corrective

action program. This assessment was accomplished by reviewing maintenance orders,

action requests, the management focus list, and attending corrective action review and

work control meetings. The inspectors: (1) verified that equipment, human performance,

and program issues were being identified by the licensee at an appropriate threshold and

that the issues were entered into the corrective action program; (2) verified that

corrective actions were commensurate with the significance of the issue; and

(3) identified conditions that might warrant additional follow-up through other baseline

inspection procedures.

b. Findings

No findings of significance were identified.

-32- ENCLOSURE 2

.3 Selected Issue Follow-up Inspection

a. Inspection Scope

In addition to the routine review, the inspectors selected the two below listed issues for a

more in-depth review. The inspectors considered the following during the review of the

licensee's actions: (1) complete and accurate identification of the problem in a timely

manner; (2) evaluation and disposition of operability/reportability issues; (3) consideration

of extent of condition, generic implications, common cause, and previous occurrences;

(4) classification and prioritization of the resolution of the problem; (5) identification of

root and contributing causes of the problem; (6) identification of corrective actions; and

(7) completion of corrective actions in a timely manner.

C August 7, 2007, Unit 3, saltwater cooling pump room thermal overload trip

December 18, 2007, Units 2 and 3, comprehensive review of operator

workarounds

Documents reviewed by the inspectors are listed in the attachment.

b. Findings

Introduction. A self revealing Green violation of 10 CFR Part 50, Appendix B,

Criterion XVI, was identified for the failure to prevent recurrence of premature tripping of

Square D thermal overloads used for equipment protection on safety-related equipment.

The licensee failed to scope the thermal overloads associated with the Unit 3 saltwater

cooling pump room because it had erroneously determined that it had sufficient margin

such that it would not be susceptible to failure. This resulted in the premature tripping of

thermal overloads for the Unit 3 saltwater cooling pump room intake structure fan on

August 8, 2007.

Description. The licensee previously had problems with spurious thermal overload trips

and received a noncited violation for untimely corrective actions to resolve the problem

(see NRC Inspection Report 05000361;362/2006-005). On October 17, 2006, the Unit 2

fuel handling building pump room emergency air conditioning Unit 2E441 Phase B

thermal overload tripped for no apparent reason with the fan turned off. The inspectors

noted that six spurious trips of other thermal overloads had occurred since December

2005. These overloads were associated with the Unit 3 fuel handling building post

accident cleanup room emergency air conditioning Unit 3E371, the Unit 2 fuel handling

building pump room emergency air conditioning Units 2E441 and 2E442, and the Unit 2

component cooling water Pump 2P024 room emergency air conditioning Unit 2E453. All

of these thermal overloads were subsequently changed out for larger devices in 2005

because of chronic problems with spurious trips.

The inspectors reviewed the history of spurious thermal overload trips and discovered

that five previous apparent cause assessments (ACEs) had been performed since

January 2001 to identify and correct spurious trips associated with thermal overloads. A

2001 ACE identified equipment aging as the cause, and directed that replacement

thermal overloads be installed. A 2002 ACE identified degraded cabling lugs as the

-33- ENCLOSURE 2

cause, and the lugs were replaced. A 2003 ACE identified the cause as insufficient

margin in the trip settings, which were adjusted. A 2004 ACE attributed a series of

spurious trips to warm weather. Finally, a 2005 ACE identified that the thermal overloads

were undersized, and that new, larger thermal overloads should be installed. The

licensee upgraded 64 thermal overloads to a larger capacity model in December 2005.

However, the inspectors concluded that the ACEs and the associated corrective actions

generated by the licensee had been ineffective in resolving the problem.

The licensee performed a root cause evaluation as part of RCE070901311 initiated in

response to the thermal overload failures. Procedure SO123-XV-50, Corrective Action

Process, Revision 7, directs a root cause evaluation for significant problems and to

prevent recurrence of the consequences of these problems. The inspectors concluded a

root cause evaluation was appropriate since Procedure SO123-XV-50 specifies criteria

for a root cause that include safety equipment failures with generic operability issues and

long-standing problems requiring escalation for resolution. The inspectors determined

these criteria were met based on the generic implications involving failures of safety

related equipment and the numerous apparent causes that had been performed since

January 2001 that had failed to correct the issue. The inspectors therefore concluded

the failure of the thermal overloads represented a significant condition adverse to quality.

The licensee implemented a detailed plan for testing the thermal overloads and X-rayed

the internals to determine if a design defect had previously gone undetected. The

licensee discovered that two mechanisms in concert with each other were causing the

spurious trips. Thermal overloads associated with small motors had a tendency to trip

early due to higher than expected current levels going through the overloads while the

associated line voltage was high in the normal band. Also, the X-ray analysis revealed

that approximately 20 percent of the sample had insufficient melting alloy, contributing to

a thermal overload tripping on lower current.

The licensee established a plan to replace the affected thermal overloads with properly

sized components that would be X-rayed for sufficient melting alloy verification prior to

installation. However, the licensee concluded sufficient margin existed in a group of 75

thermal overloads, including those associated with the Unit 3 saltwater cooling pump

room intake structure fans.

On August 8, 2007, the intake structure fan for the Unit 3 saltwater cooling pump room

tripped. The cause was subsequently determined to be a defective thermal overload on

the Phase C portion due to insufficient solder material in the thermal overload. The

thermal overload was replaced, and temperature in the Unit 3 saltwater cooling pump

never approached its design value of 98°F. The licensee has since replaced all 75

susceptible thermal overloads that were previously scoped out of the corrective action

process.

Analysis. The failure of the licensee to properly scope corrective actions to prevent the

premature tripping of thermal overloads for safety-related equipment was considered a

performance deficiency. The finding was determined to be more than minor because it

was associated with the equipment performance attribute of the mitigating systems

cornerstone and it affected the cornerstone objective by challenging the availability and

capability of safety-related components. Using the Manual Chapter 0609, Significance

-34- ENCLOSURE 2

Determination Process, Phase 1 worksheet, the finding was determined to have very low

safety significance (Green) because it did not result in an actual loss of a system safety

function, a loss of a single train of safety equipment for greater than its technical

specification allowed outage time, and did not screen as potentially risk significant due to

seismic, flooding, or severe weather initiating events. The cause of the finding has a

crosscutting aspect in the area of problem identification and resolution associated with

the corrective action program (P.1(c)) because the licensee failed to thoroughly evaluate

the extent of condition of insufficient solder material on safety-related thermal overloads.

Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in

part, that measures shall be established to ensure that for significant conditions adverse

to quality, corrective actions are taken to preclude repetition. Contrary to this, from

February 6 through August 8, 2007, the licensee failed to take corrective actions to

preclude repetition of the premature tripping of thermal overloads for safety-related

equipment, a significant condition adverse to quality. This finding has been entered into

the licensee's corrective action program as AR 070800454. Due to the licensees failure

to restore compliance from previous NCV 05000361;05000362/2006005-04, within a

reasonable time after the violation was identified, this violation is being cited as a Notice

of Violation consistent with Section VI.A of the Enforcement Policy: VIO 05000361;05000362/2007005-04, Failure to Prevent Recurrence of Premature Tripping of Square

D Thermal Overloads.

.3 Semiannual Trend Review

a. Inspection Scope

The inspectors completed a semi-annual trend review of repetitive or closely related

issues that were documented to identify trends that might indicate the existence of more

safety significant issues, specifically in the areas of procedural compliance and human

performance. The inspectors review consisted of the six month period from June 25,

2007, through December 31, 2007. When warranted, some of the samples expanded

beyond those dates to fully assess the issue. The inspectors also reviewed corrective

action program items associated with human performance improvement, and met with

representatives from the San Onofre human performance improvement team at regular

intervals. Corrective actions associated with a sample of the issues identified in the

licensee's trend report were reviewed for adequacy. Documents reviewed by the

inspectors are listed in the attachment.

b. Findings

No findings of significance were identified. However, the inspectors noted that the

licensee continued to attempt to implement human performance initiatives to prevent

personnel errors. The licensee indicated that a stand alone performance improvement

plan would be implemented by January 31, 2008.

-35- ENCLOSURE 2

4OA5 Other

.1 Temporary Instruction 2515/166, "Pressurized Water Reactor Containment Sump

Blockage," San Onofre Nuclear Generating Station, Unit 2

Temporary Instruction 2515/166 was performed at San Onofre Nuclear Generating

Station, Unit 2. The results of inspection phase of Temporary Instruction 2515/166 for

Unit 2 are subsequently documented in this report. Temporary Instruction 2515/166 for

both Unit 2 and Unit 3 will be closed out after the completion and verification of

modification commitments for Unit 2 containment sumps at the end of Refueling

Outage 15.

Listed below are the commitments and actions taken by the licensee:

1. Design and procurement of replacement sump screens

Actions Taken

Engineering Change Packet ECP#040301974-11 dated Jul 17, 2006, provides for

the design changes of containment sump to address sump blockage concerns.

This engineering change packet has undergone NRC review and supplemental

responses to the NRC are to be received no later than February 29, 2008, per

letter to Nuclear Energy Institute (NEI) from NRC: Supplemental Licensee

Responses to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On

Emergency Recirculation During Design Basis Accidents At Pressurized-Water

Reactors," dated November 30, 2007. Materials for the sump screens have been

procured and are currently being installed during Refueling Outage RF15, with

modifications expected to complete at the end of the outage.

2. Resolution of potential susceptibility of emergency core cooling system and

containment spray system pump mechanical seal to increased leakage due to

debris mix passing through the seals

Actions Taken

The licensee has completed calculations to evaluate seal leakage due to debris

ingestion. This action has undergone NRC review and supplemental responses

to the NRC are to be received no later than February 29, 2008, per letter to NEI

from NRC: Supplemental Licensee Responses to Generic Letter 2004-02,

"Potential Impact Of Debris Blockage On Emergency Recirculation During Design

Basis Accidents At Pressurized-Water Reactors," dated November 30, 2007.

3. Resolution of potential susceptibility of ECCS and CSS pump mechanical seal

cyclone separators to debris blockage

-36- ENCLOSURE 2

Actions Taken

The licensee has completed calculations to evaluate seal leakage due to debris

ingestion. This action has undergone NRC review and supplemental responses to

the NRC are to be received no later than February 29, 2008, per letter to NEI

from NRC: Supplemental Licensee Responses to Generic Letter 2004-02,

"Potential Impact Of Debris Blockage On Emergency Recirculation During Design

Basis Accidents At Pressurized-Water Reactors," dated November 30, 2007.

4. Development of a reduced qualified protective coatings zone of influence (ZOI)

Actions Taken

ALION-CAL-SONGS2933-02, Revision 1 "San Onofre Units 2 and 3 GSI-191

Containment Recirculation Sump Evaluation: Debris Generation Calculation,"

documents the assumptions and methodology that the licensee applied to

determine the ZOI and debris generated for each postulated break. This

evaluation has undergone NRC review and supplemental responses to the NRC

are to be received no later than February 29, 2008, per letter to NEI from NRC:

Supplemental Licensee Responses to Generic Letter 2004-02, "Potential Impact

Of Debris Blockage On Emergency Recirculation During Design Basis Accidents

at Pressurized-Water Reactors," dated November 30, 2007.

5. Validation of the 8 percent head loss margin adjustment factor for chemical

effects (SONGS uses Trisodium Phosphate (TSP) as a post-LOCA pH buffering

agent, and pertinent debris loads are primarily mineral wool fibrous insulation,

making NRC's Integrated Chemical Effects Test (ICET) 2 generally applicable,

but the licensee stated that chemical effects values were subject to follow-on

sump screen vendor testing, and SCE evaluations and walkdowns).

Actions Taken

Chemical effect tests were completed by Alion Science and Technology, and

directly observed by the NRC, in Warrenville, Illinois on August 17 - 18, 2006.

Open items from the NRC review are to be addressed and supplemental

responses to the NRC are to be received no later than February 29, 2008, per

letter to NEI from NRC: Supplemental Licensee Responses to Generic

Letter 2004-02, "Potential Impact Of Debris Blockage On Emergency

Recirculation During Design Basis Accidents At Pressurized-Water Reactors,"

dated November 30, 2007.

6. Containment insulation configuration control to ensure the amounts and types of

insulation remain within acceptable debris loading design margins

Actions Taken

The licensee has removed microtherm insulation on four different piping

segments in containment. This insulation is to be replaced by reflective metal

insulation where appropriate. Mineral wool insulation on the steam generators is

-37- ENCLOSURE 2

to be replaced with RMI during the steam generator replacement activities in

2009. These actions have undergone NRC review and supplemental responses to

the NRC are to be received no later than February 29, 2008, per letter to NEI

from NRC: Supplemental Licensee Responses to Generic Letter 2004-02,

"Potential Impact Of Debris Blockage On Emergency Recirculation During Design

Basis Accidents At Pressurized-Water Reactors" dated November 30, 2007.

7. Replace sump screens at SONGS Unit 2 during Refueling Outage Cycle 15

Actions Taken

Work currently ongoing and expected to be completed by the end of the refueling

outage.

8. Removal of microporous insulation on piping to be completed coincident with

sump screen replacement.

Actions Taken

Work currently ongoing and expected to be completed by the end of the refueling

outage.

9. Modification fo steel grates at the entry to the bioshield to reduce the potential for

debris blockage and resultant hold-up of recirculating water to be completed

coincident with sump screen replacement.

Actions Taken

Work currently ongoing and expected to be completed by the end of the refueling

outage.

4OA6 Meetings, Including Exit

On November 9, 2007, the engineering inspectors presented the results of the

permanent plant modifications inspection and the evaluation of changes, tests, or

experiments inspection to Dr. R. Waldo and others who acknowledged the findings.

On November 30, 2007, the health physics inspectors presented inspection results to

Mr. J. Reilly and others who acknowledged the findings.

On December 3, 2007, the inspector discussed the inspection results of the licensed

operator annual requalification examination with Mr. B. Arbour, Training Supervisor. A

telephone exit was held with Mr. Arbour, on December 3, 2007. The licensee

acknowledged the findings presented in both the briefing and the final exit meeting.

On December 13, 2007, the inspectors presented the results of this inservice inspection

to J.T. Reilly, Vice-President Engineering and Technical Services, and other members of

licensee management. Licensee management acknowledged the inspection findings.

-38- ENCLOSURE 2

On December 21, 2007, and on February 13, 2008, the inspectors presented the

quarterly inspection results to Mr. R. Ridenoure and others who acknowledged the

findings.

The inspectors confirmed that proprietary information was not provided or examined

during the inspection.

4OA7 Licensee-Identified Violations

The following violation of very low significance (Green) was identified by the licensee and

is a violation of NRC requirements which meets the criteria of Section VI of the

NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

Licensee Technical Specification Section 5.5.1.1.a requires applicable procedures

recommended in Regulatory Guide 1.33. Revision 2, Appendix A, February 1978.

Section 7e of the Appendix requires procedures for access control and a radiation

work permit system. Radiation Exposure Permit A081997001/200117-8 requires

workers to wear radiological protective clothing for entry into contaminated areas,

such as shoe covers and gloves. Contrary to this requirement, there were three

examples of security officers entering contaminated areas without the required

protective clothing. The first example occurred on October 9, 2007, when two

security guards entered a posted contaminated area in Unit 3, Room 411 of the

penetrations building, without the required radiological protective clothing. The

second example occurred on November 12, 2007, when a security guard entered

a posted contaminated area in Unit 2, Room 209 without the required radiological

protective clothing. The third example occurred November 13, 2007, when a

security guard entered a posted contaminated area in Unit 2, Room 209 without

the required radiological protective clothing. In all three examples, the area

postings had changed and with inattention to detail, the officers entered the areas

without the required radiological protective clothing. This issue was entered into

the licensee's corrective action program (Action Requests 071000551,

071100759, and 071100760). This finding is of very low safety significance

because it did not involve: (1) ALARA planning and controls, (2) an overexposure,

(3) a substantial potential for overexposure, or (4) an impaired ability to assess

dose.

ATTACHMENT: SUPPLEMENTAL INFORMATION

-39- ENCLOSURE 2

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

D. Axline, Technical Specialist, Nuclear Regulatory Affairs

D. Breig, Manager, Engineering Standards and Excellence

B. Corbett, Manager, Health Physics

J. Hirsch, Manager, Maintenance

K. Johnson, Manager, Design Engineering

R. Ridenoure, Vice President, Nuclear Generation

L. Kelly, Engineer, Nuclear Regulatory Affairs

C. McAndrews, Manager, Nuclear Oversight and Assessment

N. Quigley, Manager, Mechanical/Nuclear Maintenance Engineering

J. Reilly, Vice President, Engineering and Technical Services

A. Scherer, Manager, Nuclear Regulatory Affairs

R. St. Onge, Manager, Maintenance and Systems Engineering

T. Vogt, Manager, Special Projects

D. Wilcockson, Manager, Plant Operations

C. Williams, Manager, Compliance

T. Yackle, Manager, Operations

O. Flores, Manager, Chemistry

J. Morales, Manager, Projects

M. Cooper, Manager, Maintenance and Systems Engineering

S. Gardner, Nuclear Engineer, Nuclear Regulatory Affairs

A. Mahindrakar, Technical Specialist/Scientist, Maintenance and Systems Engineering

J. Valsvig, Technical Specialist/Scientist, Maintenance and Systems Engineering

M. McDevitt, Senior Nuclear Engineer, Engineering and Technical Services

P. Chang, Nuclear Engineer, Maintenance Engineering

A. Matheney, Senior Nuclear Engineer, Engineering and Technical Services

M. Wade, Westinghouse Representative

M. Short, Director Nuclear Oversight and Assessment

J. Todd, Manager, Nuclear Oversight and Regulatory Affairs

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000361; NOV Failure to Prevent Recurrence of Premature Tripping of

05000362/2007005-04 Square D Thermal Overloads (Section 4OA2.2)

A-1 ATTACHMENT

Opened and Closed

05000361; NCV Failure to Properly Implement Maintenance Rule

05000362/2007005-01 Requirements for Emergency Diesel Generators

(Section 1R12)05000362/2007005-02 NCV Failure to Implement Procedural Requirements for

Modificaitons in the Auxiliary Feedwater Steam Supply

Trench (Section 1R15)05000362/2007005-03 NCV Failure to Follow a Radiation Exposure Permit Requirement

(Section 2OS1)

Closed

None

Discussed

None

LIST OF DOCUMENTS REVIEWED

In addition to the documents called out in the inspection report, the following documents were

selected and reviewed by the inspectors to accomplish the objectives and scope of the

inspection and to support any findings:

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

10 CFR 50.59 Evaluations

020701289-37 Auxiliary steam system radwaste condensate return Revision 0

line rad monitor flow valve change - Fix position of

Condensate Return Valve 2/3FV-7546 and remove

2/3FIC-7546

050801215-08 Change to the U3C14 Core Fuel Loading Pattern Revision 0

060101335-13 Reduction in the number of Dome Air Circulator Fans Revision 0

Credited for Containment Sprayed and Unsprayed

Region Mixing.

060401009-06 One-time change to the testing frequency for the High Revision 0

Pressure Turbine Stop and Control Valves

A-2 ATTACHMENT

060700747-13 Perform Calculation to evaluate the effects of air pocket Revision 0

on Engineered Safety Feature pump performance.

060700747-18 Perform Calculation to evaluate the effects of air pocket Revision 1

on Engineered Safety Feature pump performance.

060800698-13 Engineering design work by Bechtel to support steam

generator replacement - Remove one Containment Revision 0

Hydrogen Recombiner E146 for one cycle of operation

to facilitate Steam Generator Replacement

060800698-44 Change to UFSAR Section 8.1, paragraph 8.1.4.3.14.B Revision 0

10 CFR 50.59 Screenings

040400696-17 Add ECP vent line at AFW pump motor outboard 09/25/2007

bearing housing to eliminate oil leak

041100092-79 Need to Evaluate U-2 CCW Fisher Butterfly valve

concerning valve taper pin issue

050300070-05 Install Steam Trap in Auxiliary Steam Cross-tie header

050901044-40 Technical specification bases change to allow 11/01/2005

substituting B00X for battery B007 and B008 for

temporary battery outage

050901044-43 Technical specification bases change to allow 11/03/2005

substituting B00X for battery B007 and B008 for

temporary battery outage

050901044-61 Phase I of the Class 1E DC system upgrade 10/27/2005

050901044-61 Technical specification bases change to allow 12/16/2005

substituting B00X for battery B007 and B008 for

temporary battery outage (update)

050901044-82 Technical specification bases change to allow 03/20/2006

substituting B00X for battery B007 and B008 for

temporary battery outage

051000132-06 Update AOV Program Procedure to update valve IST

Procedure.

051200901-07 Installation of a flow orifice downstream of 2PCV4716 07/25/2006

060200607-18 Add DC shunts to batteries 2B007 and 2B009 for 06/08/2006

monitoring current

A-3 ATTACHMENT

060200607-51 Add DC shunts to batteries 2B007 and 2B009 for 08/02/2006

monitoring current - Addition of an 800 Amp, 100 mV

DC shunt at the positive polarity of battery B00X

060400474-04 Modify required actions in procedure SO23-5-1.7 to 04/10/2006

require MODE 3 entry for 1-3 inoperable MSSVs per

steam generator

060400474-12 Modify required actions in procedure SO23-5-1.7 to 04/14/2006

require MODE 3 entry for 1-3 inoperable MSSVs per

steam generator

060400474-32 Modify required actions in procedure SO23-5-1.7 to 07/27/2006

require MODE 3 entry for 1-3 inoperable MSSVs per

steam generator

060400474-41 Modify required actions in procedure SO23-5-1.7 to 10/04/2006

require MODE 3 entry for 1-3 inoperable MSSVs per

steam generator

060500070-14 ECP# 060500070-10: Replace 3P123 Feeder Breaker 05/052006

060500211-21 Replace vertical air tank S31319MV048 05/18/2006

060500211-38 Replace vertical air tank S31319MV048 06/16/2006

060500211-43 Replace vertical air tank S31319MV048 08/10/2006

060600089-84 Increase Thermal Overload size in breakers 2BY37, 09/18/2006

3BY37, 3BZ33

060800603-02 Replace existing R3, R4 potentiometers with a new

model in AVR for EDG. 01/24/2007

060800603-16 Replace existing R3, R4 potentiometers with a new 01/24/2007

model in AVR for EDG.

060800603-29 Replace existing R3, R4 potentiometers with a new 03/07/2007

model in AVR for EDG.

061001071-19 Use of new E4C-109 battery short circuit methodology 03/28/2007

061001842-82 Upsize Thermal Overloads to avoid Spurious Trips 11/15/2006

061100895-11 Material condition of Generator Neutral Grounding

Resistor is poor.

061101272-04 Install Lifting Eye Pad on beam to allow in-line lift

capability when changing out safety valve.

A-4 ATTACHMENT

070200876-05 Code upgrade installation for CENTS computer code 02/26/2007

version 06100

070200876-06 Code upgrade installation for TORCGEOM computer 03/26/2007

code version 1.0.5

070200876-07 Code upgrade installation for REX computer code 09/20/2007

version 2.1.6

070200876-08 Code upgrade installation for CORD computer code 09/20/2007

version 1.3.7

070700512-06 Lower the Set Point of the concerned instruments and

provide Control Room indication of actual pressure.

Calculations

E4C-112, CCN 72 Class 1E 480V MCC Protection Calculation Revision 1

E4C-112, Class 1E 480V MCC Protection Calculation Revision 1

ECN A46476

E4C-112,CCN 55 Class 1E 480V MCC Protection Calculation Revision 1

M-0012-039 ESF Pump Suction with Entrained Air after RAS Revision 0

(Recirculation Actuation Signal)

N-4061-001 Post-Loss Of Coolant Accident Summary of Low Revision 2

Populated Zones and Offsite Doses

N-4061-002 Post-Loss Of Coolant Accident Containment Leakage - Revision 1

Control Room and Offsite Doses

Action Requests

050901044 060200607 060400474 060800603 061001071

Section 1R04: Equipment Alignment

Procedures

SO23-3-2.6 Shutdown Cooling System Operation Revision 24

SD-SO23-780 Auxiliary Feedwater System Revision 10

SD-SO23-120 6.9 kV, 4.16 kV and 480 V Electrical Distribution Systems Revision 16

SO23-5-1.8.1 Shutdown Nuclear Safety Revision 17

A-5 ATTACHMENT

Drawings and Calculations

SD-SO23-740 Shutdown Cooling System Revision 17

40160A Auxiliary Feedwater System - No. 1305" Revision 43

40160B Auxiliary Feedwater Steam Supply System - No. 1301" Revision 21

40160C Auxiliary Feedwater System Hydraulic Valves 2HV-4714 Revision 7

& 4731 Control Fluid System No. 1305"

40160X Auxiliary Feedwater System No. 1305 and Auxiliary Revision 4

Feedwater Steam Supply System No. 1301"

Section 1R05: Fire Protection

Procedures

2-013 Unit 2, diesel generator pre-fire plans Revision 4

3-0345 Unit 3, diesel generator pre-fire plans Revision 4

2-007 Unit 2, Safety Equipment Building (-)15'6" Revision 3

elevation

UFHA 2/3-7.0-2SE Updated Fire Hazard Analysis May 2007

Action Requests

070901019 070901022

Section 1R08: Inservice Inspections

Procedures

Number Title Revision

SO23-XXVII-20.51 Visual Examination Procedure for Operability of Nuclear 2

Components and Supports and Conditions Relating to

Their Functional Adequacy

SO23-XXVII-20.48 Liquid Penetrant Examination 1

SO23-XXVII-30.13 Risk-Informed Ultrasonic Examination of Class 1 0

Austenitic Piping Welds

SO23-XXVII-30.6 Ultrasonic Examination of Austenitic Piping Welds 2

SO23-XXVII-30.9 Ultrasonic Examination of Dissimilar Metal Piping Welds 2

A-6 ATTACHMENT

PDI-UT-10 PDI Generic Procedure for the Ultrasonic Examination of C

Dissimilar Metal Welds

9022 Reactor Coolant System Alloy 600 Material Management 5

Program

SO23-XXXIII-8.16 Reactor Coolant System Alloy 600 Inspection 5

SO23-3-2.34 Containment Access Control, Inspections and Airlocks 20

Operation

SO123-XXIV-10.1 Engineering Change Package 15

SO123-0-A4 Configuration Control 9

SO23-1-1.11.1 Plant Maintenance Procedure for Coating Service 6

Level 1 Application

SO23-XV-23.1.1 Containment Cleanliness/Loose Debris Inspection 1

SO23-V-8.17 Containment Coatings Assessment 1

QA-46 Qualification and Certification of NDE and Visual 0

Examination Personnel per ASME Section XI

WSI QAP 9.21 Liquid Penetrant Examination 1

SI-UT-126 Phased Array Ultrasonic Examination 3

T4EN51 Non-RCS Alloy 600 Boric Acid Leakage, Inspection and 1

Evaluation

T4EN52 RCS Alloy 600 Boric Acid Leakage, Inspection and 0

Evaluation

SO23-V-8.15 ISS2 Containment Boric Acid Leak Inspection 2

SO23-V-8.18 Reactor Coolant System (RCS) Leak Monitoring and 0

Investigation Guide

SO23-XV-85 Boric Acid Corrosion Control Program 1

SO23-XXXIII-8.16 Reactor Coolant System Alloy 600 Inspection 5

SO23-XXVII-3.51.9 IntraSpec UT Analysis Guidelines 5

SO23-XXVII-3.51.2 IntraSpec Eddy Current Imaging Procedure for Inspection 5

of Reactor Vessel Head Penetrations

SO23-XXVII-3.51.4 IntraSpec Ultrasonic Procedure for Inspection of Reactor 5

Vessel Head Penetrations, Time-of-Flight Ultrasonic,

Longitudinal Wave & Shear Wave

SO23-XXVII-3.51.3 IntraSpec Eddy Current Analysis Guidelines 6

A-7 ATTACHMENT

SO23-I-2.53 Containment Emergency Sump Inspection Surveillance 7

SO 123-I-11.1 Welding Filler material control 9

Corrective Action Documents

AR 070500261 AR 071101172 AR 071101173 AR 070500262

AR 070500263 AR 070500265 AR 071200384 AR 071200384

AR 060100998 AR 060101057 AR 060100961 AR 071200751

AR 071200830 AR 060901108-89

Calculations

Number Title Revision

SONG-10Q-301 Weld Overlay Sizing for Pressurizer Surge Nozzle 2

Drawings

Number Title Revision

SONG-10Q-02 Pressurizer Surge Nozzle Weld Overlay Design and Buffer 1

Layer, Shts 1 and 2

403974 Construction Drawing Surge, SONGS, Unit 2, Shts 1 and 2 0

S2-1203-ML-229 Letdown Heat Exchanger E-602 to Line 100: UA 12

2TV-0223, Sht 1

S2-1203-ML-498 Component Cooling Water, Sht 1 0

Examination Technique Specification Sheets (ETSS)

San Onofre Nuclear Generating Station Qualifying EPRI ETSSs

ETSS

ETSS #1 96004.1, 96005.2, 96008.1, 96012.1,

24013.1, 20511.1

ETSS #9 23514.1, .2, .3

ETSS #3 20510.1, 20511.1, 21409.1, 21410.1,

21998.1, 22401.1, 96703.1

ETSS #4 20510.1, 20511.1, 21409.1, 21410.1,

21998.1, 22401.1, 96703.1

A-8 ATTACHMENT

ETSS #5 96008.1, 96511.2

ETSS #6 96511.2, 99997.1

Welding Procedure Specifications and Corresponding Procedure Qualification Reports

WPS 08-08-T-001-Butter SS, Revision 0: PQRs 08-08-T-009, 08-08-TS-001, 8.8.6-OKG, and

08-08-TS-002

WPS 03-08-T-804-Bottom, Revision 0: PQRs A08202.3-3, 43-43-T-001, 03-03-T-803, and

A843256-52

WPS 1-GT-SM, Manual GTAW and/or SMAW of P-Number 1 CS, Revision 1: PQRs 51, 112,

and 153

Miscellaneous

Number Title Revision

RPA 02-0080 Quantification of Containment Latent Debris 1

ECP#04031974-74 Microtherm Insulation to RMI Change-out ECP; Unit 2

ECP# Microtherm Insulation to RMI Change-out ECP; Unit 3

04031974-58

ECP# Sump Screen Installation and Bioshield Gate

04031974-12 Modification ECP; Unit 2

ECP#04031974-11 Sump Screen Installation and Bioshield Gate

Modification ECP; Unit 3

Letter to NRC from SCE: NRC Generic Letter 2004-02 March 7, 2005

Response To NRC Request For Information San

Onofre Nuclear Generating Station Units 2 and 3

Letter to SCE from NRC: San Onofre Nuclear June 2, 2005

Generating Station Units 2 and 3-Request For

Additional Information (RAI) Related to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On

Emergency Sump Recirculation At Pressurized-Water

Reactors" (TAC NOS. MC4714 and MC4715)

Letter to NRC from SCE: NRC Generic Letter 2004-02 July 5, 2005

Response To NRC Request For Additional Information

Letter to NRC from SCE: NRC Generic Letter 2004-02 September 1,

San Onofre Nuclear Generating Station Units 2 and 3 2005

A-9 ATTACHMENT

Letter to SCE from NRC: San Onofre Nuclear February 9,

Generating Station, Units 2 and 3, Request For 2006

Additional Information RE: Response to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On

Emergency Sump Recirculation At Pressurized-Water

Reactors" (TAC NOS. MC4714 and MC4715)

Letter to PWR Owners Group from NRC: Alternative March 26,

Approach for Responding to the Nuclear Regulatory 2006

Commission Request for Additional Information Letter

RE: Generic Letter 2004-02 (TAC NOS. See

Enclosure)

Letter to PWR Owners Group from NRC: Alternative January 4,

Approach for Responding to the Nuclear Regulatory 2007

Commission Request for Additional Information Letter

RE: Generic Letter 2004-02 (TAC NOS. See

Enclosure)

San Onofre Nuclear Generating Station Units 2 and 3- May 16, 2007

Report on Results of Staff Audit of Corrective Actions

to Address Generic Letter 2004-02 (TAC NOS.

MC4714 and MC4715)

Letter to NEI from NRC: Plant-Specific Requests for November 8,

Extension of Time to Complete One or More 2007

Corrective Actions for Generic Letter 2004-02,

"Potential Impact Of Debris Blockage On Emergency

Recirculation During

Design Basis Accidents At Pressurized-Water

Reactors"

Letter to NEI from NRC: Supplemental Licensee November 30,

Responses to Generic Letter 2004-02, "Potential 2007

Impact Of Debris Blockage On Emergency

Recirculation During Design Basis Accidents At

Pressurized-Water Reactors"

ASNTCP-189-1995, ASNT Standard for Qualification

and Certification of Nondestructive Testing Personnel,

1995 Edition

Request For Relief ISI-3-25, Use of Structural Weld

Overlay and Associated Alternative Repair

Techniques

NRC Safety Evaluation for Request For Relief ISI-3-25 June 12, 2007

Weld Data Sheet, Pressurizer Surge Line Nozzle -

Weld ID DMW 02-005-031

A-10 ATTACHMENT

Welder Bead Logs for ER308L and Alloy 52M

deposition on Unit 2 Pressurizer Surge Nozzle

Steam Generator Degradation Assessment for the November 29,

Cycle 15 Refueling Outages in 2007 and 2008 2007

EA-03-009, Issuance of Order Establishing Interim February 11,

Inspection Requirements for Reactor Pressure Vessel 2003

Heads at Pressurized Water Reactors

EPRI Report 1010087, Materials Reliability Program:

Primary System Piping Butt Weld Inspection and

Evaluation Guidelines (MRP-139) August 2005

Certificate of Compliance dated 5/29/07 for ASME

Code Section II SFA5.9 Class ER 308/308L welding

material used on sacrificial layer on pressurizer surge

nozzle

Certificate of Compliance 06369301 for ASME Code

Section II, Part C SFA-5.14 Inconel 52M welding

material used to deposit weld overlay on pressurizer

surge nozzle

WSI Traveler No. 104532-TR-004 Pressurizer Surge 0

Nozzle Repair Work Steps

San Onofre Nuclear Generating Station Unit 3 Boric

Acid Corrosion Control Program (BACCP) Health

Report for Cycle 13: 12/29/2004 - 12/12/2006 May 8,

2007

Letter from T. G. San Onofre Nuclear Generating Station Units 2 and 3 June 12, 2007

Hiltz (NRC) to R. Re: Third 10-year Inservice Inspection Interval

M. Rosenblum Request ISI-3-25, Use of Structural Weld Overlays

(SCEC) and Associated Alternative Repair Techniques (TAC

NOS MD2579 and MD2580)

Guide 5 System Component Walkdown 1

Generic Letter Boric Acid Corrosion of Carbon Steel Pressure March 17,

88-05 Boundary Components in PWR Plants 1988

Information Notice Degradation of Reactor Coolant System Boundary January 5,86-109, Resulting from Boric Acid Corrosion 1995

Supplement 3

90022 Southern California Edison San Onofre Nuclear 5

Generating Station Units 2 and 3: Reactor Coolant

System Alloy 600 Material Management Program Plan

A-11 ATTACHMENT

Section 1R07A: Heat Sink Performance

SO23-I-8.94 Component Cooling Water Heat Exchanger Cleaning and Revision 8

Inspection

Action Requests

071000587 071200968

Maintenance Orders

06040726000

Section 1R11: Licensed Operator Requalification

Procedures

Lesson Plan Reactor Startup (Simulator) Revision 1

2RS767

Lesson Plan Plant Startup - Power Ascension from Mode 2 to 20% Revision 1

2RS768 Power (Simulator)

Action Requests

071000587

Maintenance Orders

06040726000

Section 1R12: Maintenance Effectiveness (Quarterly)

Procedures

SO23-3-3.23 Diesel Generator Monthly and Semi-annual Testing Revision 30

Action Requests

070300161

A-12 ATTACHMENT

Maintenance Orders

070300161-02 070300161-04

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Procedures

SO23-5-1.4 Plant Shutdown to Hot Standby Revision 13

SO23-5-1.3.1 Plant Startup from Hot Standby to Minimum Load Revision 26

Shutdown Nuclear Defense in Depth Planning Sheets Unit 3 Cycle 14 Fall Revision 0

Safety Program Midcycle Outage

SO23-5-1.8.1 Shutdown Nuclear Safety Revision 16

SO123-VIII-1 Recognition and Classification of Emergencies Revision 26

SO123-XX-6 Operator Work Around Program Revision 5

SO23-15-52.A Annunciator Panel 52A - FWCS/SBCS Revision 7

SO23-3-2.10 Main Steam Isolation Valve Operation Revision 16

SD-SO23-110 220 kV Switchyard System Revision 16

SSSPG-SO123- Assessment of Offsite Capabilities Following a Natural Revision 0

G-10 Disaster

Drawings and Calculations

SO23-507-6A-3-3 MSIV, FWIV, and FWBV Hydraulic Dump Valve Revision M

SO23-507-6A-5-3 MSIV, FWIV, and FWBV Hydraulic Dump Valve Revision M

40156FSO3 High Pressure Feedwater System Feedwater Isolation Revision 13

Valve 3HV4051 Electro-Hydraulic Actuation System

40141GSO3 Main Steam System Electro-Hydraulic Valve 3HV-8204 Revision 15

System

40141G Main Steam System Electro-Hydraulic Valve 2HV-8204 Revision 17

System

M3C14 DID #1 Barrier Map - Unit 3 Auxiliary Building (El. 50') Revision 0

M3C14 DID #1 Barrier Map - Unit 3 Safety Equipment Building (El. 15'- Revision 0

6" & 5'-3")

A-13 ATTACHMENT

M3C14 DID #3 Barrier Map - Train A Shutdown Cooling - Unit 3 Revision 0

Auxiliary Building (El. 50')

M3C14 DID #3 Barrier Map - Train A Shutdown Cooling - Unit 3 Safety Revision 0

Equipment Building (El. 15'-6" & 5'-3")

M3C14 DID #3 Barrier Map - Train B Shutdown Cooling - Unit 3 Revision 0

Auxiliary Building (El. 50')

M3C14 DID #3 Barrier Map - Train B Shutdown Cooling - Unit 3 Safety Revision 0

Equipment Building (El. 15'-6" & 5'-3")

UFSAR Fig. 8.2-1 One line Diagram - Switchyards Revision 16

Action Requests

071000609 070500815 071100595 071201499 071000250

Section 1R15: Operability Evaluations

Procedures

SO23-2-16 Operation of Waste Water systems Revision 20

SO23-20-4 Auxiliary Feedwater System Operation Revision 22

Vendor Spec Kanaline SR PVC Hose undated

Vendor Spec Prosser Standard-Line Submersible Dewatering Pumps June 2003

Series: 9-01000 & 9-01300"

Vendor Spec Prosser Standard-Line Submersible Dewatering Pumps March 2001

Series: 9-50000"

SO23-3-3.31.6 Main Feedwater System Valve Test Revision 7

SO23-3-3.31.4 Main Steam Valve Testing - Offline Revision 7

SO123-XV-5.1 Temporary Modification Control Revision 8

SO23-2-16 Use of Temporary Sump Pumps Revision 20

SO123-XV-52 Functionality Assessments and Operability Revision 7

Determinations

SO23-3-3.60.4 Saltwater Cooling Pump and Valve Testing Revision 9

Drawings and Calculations

40160A Auxiliary Feedwater System Revision 43

A-14 ATTACHMENT

40160B Auxiliary Feedwater Steam Supply System Revision 21

DCP 52 Plant design package to add trench eductor to TDAFW Revision 0

Action Requests

070500586 051200901 070500815 071100965 071000309 070500578

071000901

Section 1R17: Permanent Plant Modifications (71111.17A)

Engineering Change Packages

060400474-40 Modify required actions in procedure SO23-5-1.7 to Revision

require MODE 3 entry for 1-3 inoperable MSSVs per 09/27/2006

steam generator

060800177-07 Replacement of Diesel Generator Temperature Switch Revision 00

per SEE 000036

061001379-84 Install CCW Bypass Flow around the Unit 3 Letdown Revision 00

Heat Exchanger

061001842-16 Replace Existing TOL for Breaker 2BZ17 Revision 00

061001842-46 Replace Existing TOL for Breaker 3BZ25

Drawings

S3-1023-ML-229, Letdown Heat Exchanger, Line 100: Valve 3TV-0223 Revision 15

Sht 1

S3-1203-ML-498, Component Cooling Water Line S3-1203-ML-498-4"-D- Revision 0

Sht 1 LL1 Sys 1203

S3-1203-ML-228, S3-1203-ML-228-8"-D-LL1, From Line 099 Valve 138 to Revision 13

Sht 1 Letdown Heat Exchanger

40123BS03 Reactor Coolant Chemical & Volume Control System Revision 29

No. 1208

Permanent Plant Modifications

020701289-37 Fix Position of Condensate Return Valve 2/3FV7546 01/15/2007

and Remove 2/3FIC-7546

040400696-17 Add ECP vent line at AFW pump motor outboard 09/25/2007

bearing housing to eliminate oil leak

A-15 ATTACHMENT

050901044-40 Technical specification bases change to allow 11/01/2005

substituting B00X for battery B007 and B008 for

temporary battery outage

051200901-07 Installation of a flow orifice downstream of 2PCV4716 07/25/2006

060500211-21 Replace vertical air tank S31319MV048 05/18/2006

060800603-29 Replace existing R3, R4 potentiometers with a new 03/07/2007

model in AVR for EDG.

061101272-04 Install Pad Eye on beam over Safety Valve 3PSV0200 08/28/2007

Procedures

SO123-XV-44 10 CFR 50.59 and 72.48 Program Revision 8

Tech Spec Amendments

PCN 576 Request to revise Main Steam Safety Valve 11/07/2006

Requirements and Actions (T.S. 3.7.1)

Section 1R19: Postmaintenance Testing

Procedures

SO23-3-3.31.4 Main Steam Isolation Valve-Offline Testing Revision 7

SO23-3-3.31.6 Main Feedwater System Valve Test Revision 7

SO23-XXVII- Procedure for the Phased Array Ultrasonic Examination of Revision 1

33.14 Weld Overlaid Similar and Dissimilar Metal Welds

WSI 104125-TR- SONGS Pressurizer Surge Nozzle Repair Work Steps Revision 0

004

SO23-3-3.60.4 Saltwater Cooling Pump and Valve Testing Revision 9

SO23-3-3.31.10 Reactor Coolant Gas Vent System Test Revision 13

Miscellaneous

006-07 Repair/Replacement Plan for Weld Overlay Repair to Revision 0

Pressurizer Surge Nozzle

WPS -03-08-T-804- Weld Procedure Specification for Inconel to Stainless Revision 0

Bottom Steel

A-16 ATTACHMENT

WPS-08-08-T-001- Weld Procedure Specification for Stainless Steel Butter Revision 0

ButterSS

WPS-08-08-T-001-ButterSS Bead Log

WPS-03-08-T-804-Bottom Bead Log

Section 1R20: Refueling and Outage Activities

Procedures

SO23-5-1.4 Plant Shutdown to Hot Standby Revision 13

SO23-5-1.5 Plant Shutdown from Hot Standby to Cold Shutdown Revision 28

SO23-3-1.8 Draining the Reactor Coolant System Revision 26

SO23-5-1.8 Shutdown Operations (Mode 5 and 6) Revision 17

SO23-3-3.29 Determination of Reactor Shutdown Margin Revision 18

SO23-3-2.6 Shutdown Cooling System Operation Revision 24

SO23-I-3.5 Refueling Sequence Revision 14

SO23-5-1.3 Plant Startup from Cold Shutdown to Hot Standby Revision 30

SO23-5-1.7 Operating Instruction Revision 35

SO23-13-15 Loss Of Shutdown Cooling Revision 16

SO23-V-8.15 Containment Boric Acid Inspection Revision 2

M3C14 Defense In Depth Planning Sheets Revision 0

Action Requests

071200870 071200486

Section 1R22: Surveillance Testing

Procedures

SO23-3-3.30.8 Normal HVAC and Radiation Monitor Online Valve Test Revision 5

SO23-3-3.30.3 Component Cooling Water Seismic Makeup Valve Test Revision 11

SO23-3-3.30.2 Train A Saltwater Cooling Valve Test Revision 5

SO23-3-3.60.1 High Pressure Safety Injection Pump 2MP-018 Testing Revision 7

A-17 ATTACHMENT

SO23-3-3.60.3 Component Cooling Water Pump 2MP-024 Test Revision 8

SO23-3-3.60 Inservice Pump Testing Program Revision 8

Section 1R23: Temporary Plant Modifications

Procedures

ECP-07100097-3 Replace grounded pressurizer heater S31201ME616 Revision 0

with pressurizer heater S31201ME614"

Drawings and Calculations

32631 Elementary diagram reactor pressurizer backup heaters Revision 13

E124"

32632 Elementary diagram reactor pressurizer backup heaters Revision 27

E128"

32171 One line diagram pressurizer heaters distribution panels Revision 16

SO23-919-2- Heater element assembly Revision 4

D58

Section 1EP6 Drill Evaluation

Procedures

SO123-VIII-1 Emergency plan implementing procedures Revision 26

Emergency plan Drill 0704" October 3, 2007

SONGS Emergency Plan Revision 16

SO123-0-A7 Notification and Reporting of Significant Events Revision 5

Section 2OS1: Access Controls to Radiologically Significant Areas (71121.01)

Action Request Documents

061001562, 061100484, 061101431, 070700048, 070700545, 070701137, 070701389,

070800826, 071000512, 071000551, 071000551, 071100267, 071100759, 071100760

Audits, Self-Assessments, Observations, and Surveillance Reports

Health Physics Division Self-Assessment Reports for First, Second, and Third Quarter 2007

Leader Observation Program Records from May through November 2007

SCES-006-07

A-18 ATTACHMENT

Procedures

HP-I-2 Reactor Mode Change Checklist, Revision 14

SO123-VII-20 Health Physics Program, Revision 12

SO123-VII-20.6.1 Calculation of Dose from Skin Contamination, Revision 4

SO123-VII-20.7 Monitoring Internal Radiation Exposure, Revision 6

SO123-VII-20.9 Radiological Surveys, Revision 8

SO123-VII-20.9.6 Laboratory Analysis of Health Physics Air Samples, Revision 2

SO123-VII-20.11 Access Control Program, Revision 9

SO123-VII-20.11.1 Radiological Posting, Revision 8

Radiation Exposure Permits

A0707562000/200159, A0727070026, A0727070032/200101-12, A0819970001/200117-8

Miscellaneous

Selected Radiological Surveys during initial entry to Unit 2 Containment Refueling Outage

Unit 2 Shutdown Cooling Posting Plan

Section 2OS2: ALARA Planning and Controls (71121.02)

Action Request Documents

070400180, 070401109, 070401115, 070501042, 070600855, 070800568, 071101117,

071101118, 071101120, 071101121, 071101122, 071101124

Audits, Self-Assessments, Observations, and Surveillance Reports

Health Physics Division Self-Assessment Reports for First, Second, and Third Quarter 2007

Leader Observation Program Records from May through November 2007

SCES-006-07 and SOS-007-07

Procedures

HP-I-2 Reactor Mode Change Checklist, Revision 14

SO123-VII-20 Health Physics Program, Revision 11

SO123-VII-20.4 ALARA Program, Revision 4

SO123-VII-20.4.1 ALARA Design Change Reviews, Revision 4

SO123-VII-20.10 Radiological Work Planning and Controls, Revision 10

Radiation Exposure Permits

A0727070026, A1018940021

Miscellaneous

Reactor Coolant System Cobalt-58 Clean Up Curve for Unit 3 Midcycle 14

A-19 ATTACHMENT

Unit 2 Refueling Cycle 15 ALARA Daily Current Performance for November 26 through 29, 2007

Section 4OA1: Performance Indicator Verification (71151)

Procedures

SO23-XV-24 Quarterly NRC Performance Indicator (PI) Process, Revision 5

San Onofre Nuclear Generating Station; Station 2nd Quarter

Performace Report 2007

San Onofre Nuclear Generating Station; Station 3rd Quarter

Performace Report 2007

Miscellaneous

Quarterly Radiation Doses at the Site Boundary (Effluent Releases) for 2006 and 2007

Worker exposure records for radiological controlled area entries greater than 100 millirem

Section 4OA2: Identification and Resolution of Problems

Procedures

Policy Note 14 Human Performance Strategic Plan November 9,

2007

LIST OF ACRONYMS

AFW auxiliary feedwater

ALARA as low as reasonably achievable

AR Action Request

AVR Automatic Voltage Regulator

BACC boric acid corrision control

CAP Corrective Action Program

CFR Code of Federal Regulations

EDG emergency diesel generator

EPRI Electric Power Research Institute

LER Licensee Event Report

NCV noncited violation

NDE nondestructive examination

SSC structure, system, and component

TS Technical Specification

UFHA Updated Fire Hazards Analysis

UFSAR Updated Final Safety Analysis Report

VUHP vessel upper head penetration

A-20 ATTACHMENT

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