ML100400070

IR 05000528-09-005, 05000529-09-005, 05000530-09-005; on 10/01/09-12/31/09; Palo Verde Nuclear Generating Station, Units 1, 2, and 3 - NRC Integrated Inspection Report, and Notice of Violation

ML100400070
Person / Time
Site:	Palo Verde
Issue date:	02/09/2010
From:	Ryan Lantz NRC/RGN-IV/DRP/RPB-D
To:	Edington R Arizona Public Service Co
References
EA-09-330 IR-09-005
Download: ML100400070 (82)

See also: IR 05000528/2009005

Text

UNITE D S TATES

NUC LEAR RE GULATOR Y C OMMIS SI ON

R EG I O N I V

612 EAST LAMAR BLVD , SU ITE 400

AR L IN GTON , TEXAS 7 6 011 - 4125

February 9, 2010

EA-09-330

Randall K. Edington,

Executive Vice President, Nuclear

and Chief Nuclear Officer

Mail Station 7602

Arizona Public Service Company

P.O. Box 52034

Phoenix, AZ 85072-2034

SUBJECT: PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED

INSPECTION REPORT 05000528/2009005, 05000529/2009005, AND

05000530/2009005, AND NOTICE OF VIOLATION

Dear Mr. Edington:

On December 31, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an

integrated inspection at your Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility.

The enclosed integrated report documents the inspection findings, which were discussed on

January 26, 2010, with Mr. D. Mims, Vice President, Regulatory Affairs, and other members of

your staff.

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

compliance with the Commissions 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 and the circumstances surrounding it

are described in detail in the subject inspection report. The violation involved failure to establish

and implement an adequate procedure to control essential spray pond missile hazards and

ensure operability of the ultimate heat sink. Although determined to be of very low safety

significance (Green), this violation is being cited in the Notice because not all of the criteria

specified in Section VI.A.1 of the NRC Enforcement Policy for a noncited violation were

satisfied. Specifically, Palo Verde Nuclear Generating Station failed to restore compliance

within a reasonable time after the violation was first identified in NRC Inspection

Report 05000528, 05000529, 05000530/2008004. 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 documents three self-revealing findings of very low safety significance (Green), and

one Severity Level IV violation. All of 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

Arizona Public Service Company -2-

significance of these violations and because they were entered into your corrective action

program, the NRC is treating these findings as noncited violations consistent with Section VI.A.1

of the NRC Enforcement Policy. If you contest these noncited violations, 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, 612 E. Lamar Blvd., Suite 400, Arlington, Texas 76011-4125; the

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

DC 20555-0001; and the NRC Resident Inspector at the Palo Verde Nuclear Generating

Station, Units 1, 2, and 3, facility. In addition, if you disagree with the characterization of any

finding in this report, you should provide a response within 30 days of the date of this inspection

report, with the basis for your disagreement, to the Regional Administrator, Region IV, and the

NRC Resident Inspector at Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility.

The information you provide will be considered in accordance with Inspection Manual

Chapter 0305.

In accordance with 10 CFR 2.390 of the NRCs 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), accessible from the NRC Web site at

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

Sincerely,

/RA/

Ryan Lantz, Chief

Projects, Branch D

Division of Reactor Projects

Docket Nos. 50-528

50-529

50-530

License Nos. NPF-41

NPF-51

NPF-74

Enclosures:

1. Notice of Violation.

2. NRC Inspection Report 05000528/2009005, 05000529/2009005, and 05000530/2009005

w/Attachment: Supplemental Information

cc w/enclosures:

Mr. Steve Olea

Arizona Corporation Commission

1200 W. Washington Street

Phoenix, AZ 85007

Arizona Public Service Company -3-

Mr. Douglas Kent Porter

Senior Counsel

Southern California Edison Company

Law Department, Generation Resources

P.O. Box 800

Rosemead, CA 91770

Chairman

Maricopa County Board of Supervisors

301 W. Jefferson, 10th Floor

Phoenix, AZ 85003

Mr. Aubrey V. Godwin, Director

Arizona Radiation Regulatory Agency

4814 South 40 Street

Phoenix, AZ 85040

Mr. Ron Barnes, Director

Regulatory Affairs

Palo Verde Nuclear Generating Station

Mail Station 7636

P.O. Box 52034

Phoenix, AZ 85072-2034

Mr. Dwight C. Mims

Vice President

Regulatory Affairs and Plant Improvement

Palo Verde Nuclear Generating Station

Mail Station 7605

P.O. Box 52034

Phoenix, AZ 85072-2034

Mr. Jeffrey T. Weikert

Assistant General Counsel

El Paso Electric Company

Mail Location 167

123 W. Mills

El Paso, TX 79901

Mr. Eric Tharp

Los Angeles Department of Water and Power

Southern California Public Power Authority

P.O. Box 51111, Room 1255-C

Los Angeles, CA 90051-0100

Mr. James Ray

Public Service Company of New Mexico

2401 Aztec NE, MS Z110

Arizona Public Service Company -4-

Albuquerque, NM 87107-4224

Mr. Geoffrey M. Cook

Southern California Edison Company

5000 Pacific Coast Hwy. Bldg. D21

San Clemente, CA 92672

Mr. Robert Henry

Salt River Project

6504 East Thomas Road

Scottsdale, AZ 85251

Mr. Brian Almon

Public Utility Commission

William B. Travis Building

P.O. Box 13326

Austin, TX 78701-3326

Environmental Program Manager

City of Phoenix

Office of Environmental Programs

200 West Washington Street

Phoenix, AZ 85003

Mr. John C. Taylor

Director, Nuclear Generation

El Paso Electric Company

340 East Palm Lane, Suite 310

Phoenix, AZ 85004

Chief, Technological Hazards

Branch

FEMA Region IX

1111 Broadway, Suite 1200

Oakland, CA 94607-4052

Arizona Public Service Company -5-

Electronic distribution by RIV:

Regional Administrator (Elmo.Collins@nrc.gov)

Deputy Regional Administrator (Chuck.Casto@nrc.gov)

DRP Director (Dwight.Chamberlain@nrc.gov)

DRP Deputy Director (Anton.Vegel@nrc.gov)

DRS Director (Roy.Caniano@nrc.gov)

DRS Deputy Director (Troy.Pruett@nrc.gov)

Senior Resident Inspector (Ryan.Treadway@nrc.gov)

Resident Inspector (Michelle.Catts@nrc.gov)

Resident Inspector (Joseph.Bashore@nrc.gov)

Resident Inspector (Mica.Baquera@nrc.gov)

Branch Chief, DRP/D (Ryan.Lantz@nrc.gov)

PV Administrative Assistant (Regina.McFadden@nrc.gov)

Senior Project Engineer, DRP/D (Don.Allen@nrc.gov)

Public Affairs Officer (Victor.Dricks@nrc.gov)

Public Affairs Officer (Lara.Uselding@nrc.gov)

Branch Chief, DRS/TSB (Michael.Hay@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

Congressional Affairs Officer (Jenny.Weil@nrc.gov)

OEMail Resource

Inspection Reports/MidCycle and EOC Letters to the following:

ROPreports

Only inspection reports to the following:

DRS/TSB STA (Dale.Powers@nrc.gov)

OEDO RIV Coordinator (Leigh.Trocine@nrc.gov)

File located: R:\_REACTORS\_PV\2009\PV2009-005RP-RIT.doc ML 100400070

SUNSI Rev Compl. ; Yes No ADAMS  ; Yes No Reviewer Initials RL

Publicly Avail  ; Yes No Sensitive Yes ; No Sens. Type Initials RL

RIV:RI:DRP/D RI:DRP/D RI:DRP/D SRI:DRP/D SPE:DRP/D C:DRS/OB

JBashore MCatts MBaquera RTreadway DAllen MHaire

/RA by Email/ /RA by Email/ /RA by Email/ /RA by Email/ /RA/ /RA/

2/8/10 2/2/10 2/2/10 2/2/10 2/8/10 2/8/10

C:DRS/EB1 C:DRS/EB2 C:DRS/PSB1 C:DRS/PSB2 C:DRS/TSB C:DRP/PBD

TFarnholtz NOKeefe MShannon GWerner MHay RLantz

/RA/ /RA/ /RA/ /D for/ /DAP for / /RA/

1/27/10 1/27/10 1/28/10 1/28/10 1/29/10 2/8/10

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

NOTICE OF VIOLATION

Arizona Public Service Company Docket Nos.: 50-528,-529,-530

Palo Verde Nuclear Generating Station License Nos.: NPF-41, -51, -74

EA-09-330

During an NRC inspection conducted on October 1 through December 31, 2009, 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 V, Instructions, Procedures, and Drawings,

requires, in part, that activities affecting quality shall be prescribed by documented

instructions, procedures, or drawings, and shall be accomplished in accordance with

these instructions, procedures, or drawings.

Contrary to the above, from July 11, 2008 through December 31, 2009, the licensee

failed to prescribe adequate procedures for the essential spray ponds. Specifically, the

licensee failed to ensure an adequate procedure was available to control essential spray

pond missile hazards and ensure operability of the ultimate heat sink.

This violation is associated with a Green Significance Determination Process finding.

Pursuant to the provisions of 10 CFR Part 2.201, Arizona Public Service Company is hereby

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

Commission, ATTN: Document Control Desk, Washington, DC 20555-0001 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 of Violation (Notice), within 30 days of the date of the letter

transmitting this Notice. This reply should be clearly marked as a "Reply to Notice of

Violation EA-09-330," 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 website at www.nrc.gov/reading-rm/pdr.html or 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 specifically identify the portions of your response that you seek to have

-1- Enclosure 1

withheld and provide in detail the basis 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 Part 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 Part 73.21.

Dated this 8th day of February 2010.

-2- Enclosure 1

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Dockets: 50-528, 50-529, 50-530

Licenses: NPF-41, NPF-51, NPF-74

Report: 05000528/2009005, 05000529/2009005, 05000530/2009005

Licensee: Arizona Public Service Company

Facility: Palo Verde Nuclear Generating Station, Units 1, 2, and 3

Location: 5951 S. Wintersburg Road

Tonopah, Arizona

Dates: October 1 through December 31, 2009

Inspectors: J. Bashore, Resident Inspector

M. Baquera, Resident Inspector

M. Catts, Resident Inspector

R. Treadway, Senior Resident Inspector

B. Henderson, Reactor Inspector

M. Young, Reactor Inspector

L. Carson II, Senior Health Physicist

T. Farina, Reactor Inspector

B. Larson, Senior Operations Engineer

Approved By: Ryan Lantz, Chief, Project Branch D

Division of Reactor Projects

-1- Enclosure 2

SUMMARY OF FINDINGS

IR 05000528/2009005, 05000529/2009005, 05000530/2009005; 10/01/09 - 12/31/09;

Palo Verde Nuclear Generating Station, Units 1, 2, and 3; Op. Evals., Refuel and Outage Act.,

Access Cont. To Rad. Sig. Areas, ALARA Plans & Cont., Event Flwp.

This report covered a 3-month period of inspection by resident and regional inspectors. Four

Green findings, of which one is a cited violation and three are noncited violations, and one

Severity Level IV finding were identified. 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 4, dated December 2006.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

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

Criterion V, "Instructions, Procedures, and Drawings," was identified for the

failure of operations personnel to adequately establish and implement

procedures associated with a loss of instrument air to containment. Specifically,

on December 3, 2009, the alarm response and abnormal operating procedures

available to the Unit 3 control room operating staff were inadequate to

consistently diagnose and mitigate a loss of instrument air to containment. This

issue was entered into the licensees corrective action program as Condition

Report/Disposition Request (CRDR) 3411457.

The performance deficiency associated with this finding involved the failure of

operations personnel to adequately establish and implement alarm response and

abnormal operating procedures associated with a loss of instrument air to

containment. The finding is more than minor because it is associated with the

procedure quality attribute of the Initiating Events Cornerstone and affects the

cornerstone objective of limiting the likelihood of those events that upset plant

stability and challenge critical safety functions during shutdown as well as power

operations. Using Manual Chapter 0609.04, "Phase 1 - Initial Screening and

Characterization of Findings," the finding was determined to have very low safety

significance because the finding did not contribute to both the likelihood of a

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

available. This finding has a crosscutting aspect in the area of problem

identification and resolution associated with the corrective action program

because the licensee failed to implement the corrective action program with a low

threshold for identifying issues P.1(a) (Section 4OA3).

Cornerstone: Mitigating Systems

• Green. The inspectors identified a cited violation of 10 CFR Part 50, Appendix B,

Criterion V, "Instructions, Procedures, and Drawings," for the failure of

engineering personnel to establish adequate procedures to ensure evaluation

and approval of transient missile hazards that have an effect on the operability of

-2- Enclosure 2

the essential spray ponds. Specifically, since January 15, 1997, civil engineering

personnel failed to develop an adequate procedure to verify missile density

criteria are not exceeded to ensure operability of the essential spray ponds

during severe weather. Due to the licensees failure to restore compliance from

the previous NCV 05000528/2008004-04 within a reasonable time, this violation

is being cited in a Notice of Violation consistent with Section VI.A of the NRC

Enforcement Policy. This issue was entered into the licensee's corrective action

program as CRDR 3397839.

The finding is more than minor because it is associated with the external factors

attribute of the Mitigating Systems Cornerstone and affects the cornerstone

objective of ensuring the reliability of systems that respond to initiating events to

prevent undesirable consequences. Using Manual Chapter 0609.04, "Phase 1 -

Initial Screening and Characterization of Findings," the finding was determined to

have very low safety significance because the finding did not result in a loss of

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

greater than its technical specification allowed outage time, or screen as

potentially risk significant due to a seismic, flooding, or severe weather initiating

event. This finding has a crosscutting aspect in the area of problem identification

and resolution associated with the corrective action program because

appropriate corrective actions were not taken to address safety issues and

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

and complexity P.1(d) (Section 1R15).

Cornerstone: Barrier Integrity

• Green. A self-revealing noncited violation of Technical Specification 5.4.1.a,

Procedures, was identified for the failure of maintenance personnel to maintain

containment closure capability as required by Procedure 70DP-0RA01,

Shutdown Risk Assessments. Specifically, on October 8, 2009 maintenance

personnel designated for emergency closure of the containment equipment hatch

left containment to attend a safety briefing for more than four hours before they

returned to perform their required duties. This issue was entered into the

licensee's corrective action program as PVAR 3389284.

The performance deficiency associated with this finding involved the failure of

maintenance personnel to follow the requirements of Procedure 70DP-0RA01,

Shutdown Risk Assessments, and ensure a containment closure team was in

containment and capable of closing the containment equipment hatch within

30 minutes. The finding was more than minor because it affected the

configuration control attribute of the Barrier Integrity Cornerstone, and affected

the cornerstone objective to provide reasonable assurance that physical design

barriers protect the public from radionuclide releases caused by accidents or

events. Using Manual Chapter 0609, Appendix H, Containment Integrity

Significance Determination Process, the finding was determined to be a type B

finding because it affected only large early release frequency, not core damage

frequency, at shutdown. A phase 2 analysis using Table 6.4, Phase 2 Risk

Significance-Type B Findings at Shutdown, was performed with the following

considerations: the plant was in cold shutdown with the reactor coolant system

vented, steam generators not available, and within eight days of shutdown, the

condition existed for less than eight hours, and there was mitigation equipment

-3- Enclosure 2

out of service. The senior reactor analyst determined that that the finding has

very low safety significance (Green) based on the short time period that the

condition existed, the low probability of a loss of cooling event during this period

with two fully-functional trains available, and the time it would have taken to close

the hatch was well less than the time until the core would have become

uncovered. This finding was determined to have a cross cutting aspect in the

area of human performance associated with work control because the licensee

failed to appropriately coordinate work activities by incorporating actions to

address plant conditions that may affect work activities H.3(b) (Section 1R20).

Cornerstone: Occupational Radiation Safety

• Green. A self-revealing noncited violation of Technical Specification 5.7.1, High

Radiation Areas, was identified for the failure of radiological protection personnel

to perform a prejob briefing to ensure workers are aware of radiological

conditions in a high radiation area as required by the radiation exposure permit.

Specifically, on October 20, 2009, nine contract workers were preparing to install

an anticontamination sock over the Unit 2 old reactor vessel head, signed onto a

radiation exposure permit which allowed access to a high radiation area but

failed to receive a brief on the local dose rates surrounding the reactor vessel

head by the job coverage radiation protection technician. This issue was entered

into the corrective action program as CRDR 3394172.

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

control attribute of the Occupational Radiation Safety Cornerstone and affected

the cornerstone objective to properly control access to a high radiation area and

had the potential to increase personnel dose. Using Manual Chapter 0609,

Appendix C, Occupational Radiation Safety Significance Determination

Process, the finding was determined to have very low safety significance

because it was not associated with as low as reasonably achievable, there was

no overexposure, there was no substantial potential for an overexposure; and the

ability to assess dose was not compromised. This finding has a crosscutting

aspect in the area of human performance associated with work practices

because the licensees radiation protection staff failed to communicate

expectations to contract personnel H.4(b) (Section 2OS1).

Cornerstone: Public Radiation Safety

• Severity Level IV. The inspectors identified a noncited violation of 10 CFR 50.71

Maintenance of Records, because the licensee failed to update their updated

final safety analysis report with submittals that include the effects of a change

made to the facility. Specifically, the licensee built the old steam generator

storage facility on the owner controlled area for long-term radwaste storage of six

decommissioned steam generators and three reactor vessel heads and failed to

update the updated final safety analysis report to include these changes to the

facility and all safety analyses and evaluations performed. This issue was

entered in the licensees corrective action program as CRDR 3398042.

This issue was dispositioned using traditional enforcement because it had the

potential for impacting the NRCs ability to perform its regulatory function. The

finding is more than minor because it has a material impact on licensed activities

-4- Enclosure 2

in that the six decommissioned steam generators and the Unit 2 reactor vessel

head, with a significant radioactive source term have been relocated from the

plant radiological controlled area to the owner controlled area. In addition, the

radwaste management program was affected because the licensee determined

that this low-level radwaste facility will store these large components until the site

is decommissioned. The finding is characterized as a Severity Level IV, noncited

violation in accordance with NRC Enforcement Policy, Supplement I, and was

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

Enforcement Policy. This finding was reviewed for crosscutting aspects and

none were identified because the performance deficiency is not indicative of

current performance (Section 2OS2).

B. Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee has been

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

been entered into the licensees corrective action program. This violation and corrective

action tracking numbers are listed in Section 4OA7 of this report.

.

-5- Enclosure 2

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at essentially full power for the duration of the inspection period.

Unit 2 operated at full power until October 3, 2009, when the unit was shutdown for Refueling

Outage 2R15. The unit was restarted on December 1, 2009, and returned to full power on

December 6, 2009. On December 9, 2009, control room operators lowered reactor power to

approximately 60 percent power and subsequently to 10 percent power to take the main turbine

offline for repairs on the C main transformer. The unit was restarted on December 12, 2009,

and returned to full power on December 15, 2009, and remained at full power for the duration of

the inspection period.

Unit 3 operated at full power until December 3, 2009, when the reactor was tripped and the unit

shutdown due to a loss of instrument air to containment. Repairs were made to the instrument

air system and the unit was restarted on December 5, 2009, and returned to full power on

December 11, 2009, and remained at full power for the duration of the inspection period.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment (71111.04)

.1 Partial Walkdown

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant

systems:

• November 11, 2009, Unit 1, containment spray system train B

• November 25, 2009, Unit 2, recirculation actuation system train A and B

• December 8, 2009, Unit 2, essential chilled water system train B

The inspectors selected these systems based on their risk significance relative to the

Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted

to identify any discrepancies that could affect the function of the system, and, therefore,

potentially increase risk. The inspectors reviewed applicable operating procedures,

system diagrams, Updated Final Safety Analysis Report (UFSAR), technical

specification requirements, administrative technical specifications, outstanding work

orders, condition reports, and the impact of ongoing work activities on redundant trains

of equipment in order to identify conditions that could have rendered the systems

incapable of performing their intended functions. The inspectors also walked down

accessible portions of the systems to verify system components and support equipment

were aligned correctly and operable. The inspectors examined the material condition of

the components and observed operating parameters of equipment to verify that there

were no obvious deficiencies. The inspectors also verified that the licensee had properly

-6- Enclosure 2

identified and resolved equipment alignment problems that could cause initiating events

or impact the capability of mitigating systems or barriers and entered them into the

corrective action program with the appropriate significance characterization. Specific

documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three partial system walkdown samples as

defined in Inspection Procedure 71111.04-05.

b. Findings

No findings of significance were identified.

.2 Complete Walkdown

a. Inspection Scope

On November 13, 2009, the inspectors performed a complete system alignment

inspection of the Unit 2 shutdown cooling system train B to verify the functional capability

of the system. The inspectors selected this system because it was considered both

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

inspectors walked down the system to review mechanical and electrical equipment

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

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

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

debris did not interfere with equipment operation. The inspectors reviewed a sample of

past and outstanding work orders to determine whether any deficiencies significantly

affected the system function. In addition, the inspectors reviewed the corrective action

program database to ensure that system equipment alignment problems were being

identified and appropriately resolved. Specific documents reviewed during this

inspection are listed in the attachment.

These activities constitute completion of one complete system walkdown sample as

defined in Inspection Procedure 71111.04-05.

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

Quarterly Fire Inspection Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns that were focused on availability,

accessibility, and the condition of firefighting equipment in the following risk-significant

plant areas:

• October 26, 2009, Unit 3, condensate storage pump house and tunnel

• October 27, 2009, Unit 3, spray pond pump house

-7- Enclosure 2

• November 11, 2009, Unit 2, auxiliary building 40 foot and 77 foot elevations

• November 11, 2009, Unit 2, auxiliary building 88 foot and 140 foot elevations

The inspectors reviewed areas to assess if licensee personnel had implemented a fire

protection program that adequately controlled combustibles and ignition sources within

the plant; effectively maintained fire detection and suppression capability; maintained

passive fire protection features in good material condition; and had implemented

adequate compensatory measures for out of service, degraded or inoperable fire

protection equipment, systems, or features, in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk

as documented in the plants Individual Plant Examination of External Events with later

additional insights, their potential to affect equipment that could initiate or mitigate a plant

transient, or their impact on the plants ability to respond to a security event. Using the

documents listed in the attachment, the inspectors verified that fire hoses and

extinguishers were in their designated locations and available for immediate use; that

fire detectors and sprinklers were unobstructed, that transient material loading was

within the analyzed limits; and fire doors, dampers, and penetration seals appeared to

be in satisfactory condition. The inspectors also verified that minor issues identified

during the inspection were entered into the licensees corrective action program.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four quarterly fire protection inspection samples

as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (71111.06)

a. Inspection Scope

The inspectors reviewed the UFSAR, the flooding analysis, and plant procedures to

assess susceptibilities involving internal flooding; reviewed the corrective action program

to determine if licensee personnel identified and corrected flooding problems; inspected

underground bunkers/manholes to verify the adequacy of sump pumps, level alarm

circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and

verified that operator actions for coping with flooding can reasonably achieve the desired

outcomes. The inspectors also walked down the areas listed below to verify the

adequacy of equipment seals located below the flood line, floor and wall penetration

seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms,

and control circuits, and temporary or removable flood barriers. Specific documents

reviewed during this inspection are listed in the attachment.

• November 10, 2009, Unit 2, underground cable vaults for auxiliary feedwater

pumps

• November 20, 2009, Units 1, 2, and 3, underground cable vaults for station

blackout generator

-8- Enclosure 2

These activities constitute completion of two flood protection measures inspection

sample as defined in Inspection Procedure 71111.06-05.

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, and Boric Acid Corrosion Control

(71111.08-02.01)

a. Inspection Scope

The inspectors observed and reviewed three types of nondestructive examination

activities and two welds on the reactor coolant system pressure boundary.

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE

Auxiliary Main steam to auxiliary feedwater Ultrasonic Test

Feedwater pump p01 (53-25)

Auxiliary Main steam to auxiliary feedwater Magnetic Test

Feedwater pump p01 (53-21)

Auxiliary Main steam to auxiliary feedwater Magnetic Test

Feedwater pump p01 (53-22)

Auxiliary Main steam to auxiliary feedwater Magnetic Test

Feedwater pump p01 (53-23)

Auxiliary Main steam to auxiliary feedwater Magnetic Test

Feedwater pump p01 (53-25)

High Pressure Pump A discharge piping (106-1) Ultrasonic Test

Safety Injection

High Pressure Pump A discharge piping (106-21) Ultrasonic Test

Safety Injection

High Pressure Pump A discharge piping (106-1) Penetrant Test

Safety Injection

High Pressure Pump A discharge piping (106-21) Penetrant Test

Safety Injection

-9- Enclosure 2

The inspectors reviewed records for the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE

Safety Injection Cold leg safety injection nozzle phased array Ultrasonic

dissimilar metal butt weld (9-10) Test

Safety Injection Cold leg safety injection nozzle phased array Ultrasonic

dissimilar metal butt weld (11-10) Test

Safety Injection Cold leg safety injection nozzle phased array Ultrasonic

dissimilar metal butt weld (13-10) Test

Safety Injection Cold leg safety injection nozzle phased array Ultrasonic

dissimilar metal butt weld (15-9) Test

Auxiliary Main steam to auxiliary feedwater Ultrasonic Test

Feedwater pump P01 (53-21)

Auxiliary Main steam to auxiliary feedwater Ultrasonic Test

Feedwater pump P01 (53-22)

Auxiliary Main steam to auxiliary feedwater Ultrasonic Test

Feedwater pump P01 (53-23)

Chemical 2PCHAV328 - seal weld body to Penetrant Test

Volume and bonnet

Control System

During the review and observation of each examination, the inspectors verified that

activities were performed in accordance with the ASME Code requirements and

applicable procedures. The inspectors also verified that the qualifications of all

nondestructive examination technicians performing the inspections were current.

The inspectors observed and reviewed records for the following welds:

SYSTEM WELD IDENTIFICATION WELDING TYPE

Chemical 2PCHAV328 -seal weld body to gas tungsten arc welding

Volume And bonnet

Control System

Safety Injection 24 inch diameter butt welds - gas tungsten arc welding

System sump isolation valve replacement

(3187434-30)

The inspectors verified, by review, that the welding procedure specifications and the

welders had been properly qualified in accordance with ASME Code,Section IX,

requirements. The inspectors also verified, through observation and record review, that

essential variables for the welding process were identified, recorded in the procedure

qualification record, and formed the bases for qualification of the welding procedure

- 10 - Enclosure 2

specifications. Specific documents reviewed during this inspection are listed in the

attachment.

These actions constitute completion of the requirements for Section 02.01.

b. Findings

No findings of significance were identified.

.2 Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)

a. Inspection Scope

The Unit 2 reactor pressure vessel head is being replaced during this outage. The

required inspections have been performed and documented in Section 4OA5 of this

report.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)

a. Inspection Scope

The inspectors evaluated the implementation of the licensees boric acid corrosion

control program for monitoring degradation of those systems that could be adversely

affected by boric acid corrosion. The inspectors reviewed the documentation associated

with the licensees boric acid corrosion control walkdown as specified in

Procedure 73DP-9ZC01, Boric Acid Corrosion Control Program, Revision 3, and

Procedure 70TI-9ZC01, Boric Acid Walkdown Leak Detection, Revision 9. The

inspectors also reviewed the visual records of the components and equipment. The

inspectors verified that the visual inspections emphasized locations where boric acid

leaks could cause degradation of safety-significant components. The inspectors also

verified that there were no engineering evaluations for those components where boric

acid was identified. The inspectors confirmed that the corrective actions performed for

evidence of boric acid leaks were consistent with requirements of the ASME Code.

Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.03.

b. Findings

No findings of significance were identified.

.4 Steam Generator Tube Inspection Activities (71111.08-02.04)

a. Inspection Scope

The inspectors assessed the in-situ screening criteria to assure consistency between

assumed nondestructive examination flaw sizing accuracy and data from the Electrical

- 11 - Enclosure 2

Power Research Institute (EPRI) examination technique specification sheets. No

conditions were identified that warranted in-situ pressure testing.

Due to the tube wear identified during the previous outage, a 100 percent review of all

tubes in both steam generators was performed during this outage. 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 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 number of

identified indications fell within the range of prediction and was consistent with

predictions from the vendor for the previous outage. No new damage mechanisms were

identified during this inspection. The licensee plugged ten tubes in steam generator 21

and four tubes in steam generator 22. A loose part, believed to be an eggcrate wedge,

has been identified in steam generator 21. It was identified in the previous outage, but

has migrated downward. The tubes in the vicinity were plugged and staked.

The inspection procedure specified confirmation that the steam generator tube eddy

current test scope and expansion criteria meet technical specification requirements,

EPRI guidelines, and commitments made to the NRC. The inspectors evaluated the

recommended steam generator tube eddy current test scope established by technical

specification 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 technical specification requirements, EPRI guidelines, and

commitments made to the NRC.

As mentioned above, the base scope inspection plan required 100 percent tube

inspection for this outage (2R15). The inspection scope for 2R15 included:

• 100 percent visual inspection of installed plugs

• Tubesheet secondary side foreign object search and retrieval

• 100 percent bobbin examination in both steam generators from tube end to tube end

• Plus point inspection of U-bends in rows 1 through 4

• Plus point inspection of special interest locations

Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements of Section 02.04.

b. Findings

No findings of significance were identified.

- 12 - Enclosure 2

.5 Identification and Resolution of Problems (71111.08-02.05)

a. Inspection scope

The inspectors reviewed eight condition reports, which dealt with inservice inspection

activities and found the corrective actions were appropriate. The specific condition

reports 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. Specific documents reviewed during this inspection are listed in

the attachment.

These actions constitute completion of the requirements of Section 02.05.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11)

.1 Annual Inspection

a. Inspection Scope

The inspector reviewed the annual operating test results for 2009. Since this was the

first half of the biennial requalification cycle, the licensee was not required 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," thresholds. This review included the

test results for a total of 20 crews (15 shift crews and 5 staff crews) composed of 70

senior reactor operators and 34 reactor operators. All individuals and crews passed all

portions of the operating test.

The inspector completed one sample.

b. Findings

No findings of significance were identified.

.2 Quarterly Inspection

a. Inspection Scope

On December 9, 2009, the inspectors observed a crew of licensed operators in the

plants simulator to verify that operator performance was adequate, evaluators were

identifying and documenting crew performance problems and training was being

conducted in accordance with licensee procedures. The inspectors evaluated the

following areas:

• Licensed operator performance

- 13 - Enclosure 2

• Crews clarity and formality of communications

• Crews ability to take timely actions in the conservative direction

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification

actions and emergency plan actions and notifications

The inspectors compared the crews performance in these areas to pre-established

operator action expectations and successful critical task completion requirements.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one quarterly licensed operator requalification

program inspection sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk

significant systems:

• November 2, 2009, Unit 3, main generator regulator inverter failure

• December 11, 2009, Unit 2, main transformer elevated temperatures

The inspectors reviewed events such as where ineffective equipment maintenance has

resulted in valid or invalid automatic actuations of engineered safeguards systems and

independently verified the licensee's actions to address system performance or condition

problems in terms of the following:

• Implementing appropriate work practices

• Identifying and addressing common cause failures

• Scoping of systems in accordance with 10 CFR 50.65(b)

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

- 14 - Enclosure 2

• Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or (a)(2)

• Verifying appropriate performance criteria for structures, systems, and

components classified as having an adequate demonstration of performance

through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as

requiring the establishment of appropriate and adequate goals and corrective

actions for systems classified as not having adequate performance, as described

in 10 CFR 50.65(a)(1)

The inspectors assessed performance issues with respect to the reliability, availability,

and condition monitoring of the system. In addition, the inspectors verified maintenance

effectiveness issues were entered into the corrective action program with the appropriate

significance characterization. Specific documents reviewed during this inspection are

listed in the attachment.

These activities constitute completion of two quarterly maintenance effectiveness

samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings of significance were identified.

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

a. Inspection Scope

Risk Assessment and Management of Risk

The inspectors reviewed licensee personnel's evaluation and management of plant risk

for the maintenance and emergent work activities affecting risk-significant and

safety-related equipment listed below to verify that the appropriate risk assessments

were performed prior to removing equipment from service for work:

• September 14, 2009 and October 19, 2009, Unit 1, emergent work risk

assessment associated with switchyard breaker 982

• October 22, 2009, Unit 3, excore control channel 1 out of service for emergent

work

• November 9 through 17, 2009, Unit 2, high pressure safety injection pump train B

removed from service for corrective maintenance concurrent with emergency

diesel generator train A unavailability during refuelling outage

• December 8, 2009, Unit 2, emergency diesel generator train A out of service for

planned maintenance

• December 11, 2009, Unit 2, main transformer C out of service for emergent

repairs of the neutral bushing

The inspectors selected these activities based on potential risk significance relative to

the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified

that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)

- 15 - Enclosure 2

and that the assessments were accurate and complete. When licensee personnel

performed emergent work, the inspectors verified that the licensee personnel promptly

assessed and managed plant risk. The inspectors reviewed the scope of maintenance

work, discussed the results of the assessment with the licensee's probabilistic risk

analyst or shift technical advisor, and verified plant conditions were consistent with the

risk assessment. The inspectors also reviewed the technical specification requirements

and inspected portions of redundant safety systems, when applicable, to verify risk

analysis assumptions were valid and applicable requirements were met. Specific

documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five maintenance risk assessments and

emergent work control inspection samples as defined in Inspection

Procedure 71111.13-05.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors reviewed the following issues:

• April 10, 2009, Units 1, 2, and 3, operability determination for lack of design basis

accident testing for containment coating

• September 28, 2009, Units 1, 2, and 3, operability determination for start-up

transformer AE-NAN-X01 sudden fault pressure relay annunciator single channel

failure

• October 26, 2009, Unit 2, operability determination for air leak on emergency

diesel generator B cylinder 9R

• October 31, 2009, Unit 2, operability determination for the failure of 2PCHAV190

check valve

• November 4, 2009, Unit 3, essential spray pond A bacterial analysis

• November 11, 2009, Unit 2, essential cooling water heat exchanger A

circumferential cracks

• November 19, 2009, Units 1, 2 and 3, operability determination for radioactive

water storage tank degraded condition

The inspectors selected these potential operability issues based on the risk-significance

of the associated components and systems. The inspectors evaluated the technical

adequacy of the evaluations to ensure that technical specification operability was

properly justified and the subject component or system remained available such that no

unrecognized increase in risk occurred. The inspectors compared the operability and

design criteria in the appropriate sections of the technical specifications and UFSAR to

- 16 - Enclosure 2

the licensees evaluations, to determine whether the components or systems were

operable. Where compensatory measures were required to maintain operability, the

inspectors determined whether the measures in place would function as intended and

were properly controlled. The inspectors determined, where appropriate, compliance

with bounding limitations associated with the evaluations. Additionally, the inspectors

also reviewed a sampling of corrective action documents to verify that the licensee was

identifying and correcting any deficiencies associated with operability evaluations.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of seven operability evaluation inspection samples

as defined in Inspection Procedure 71111.15-05.

b. Findings

Introduction. The inspectors identified a Green cited violation of 10 CFR Part 50,

Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure of

engineering personnel to establish adequate procedures to ensure evaluation and

approval of transient missile hazards that have an effect on the operability of the

essential spray ponds. Specifically, since January 15, 1997, civil engineering personnel

failed to develop an adequate procedure to verify missile density criteria are not

exceeded to ensure operability of the essential spray ponds during severe weather. This

issue was entered into the licensee's corrective action program as Condition

Report/Disposition Request (CRDR) 3397839.

Description. On October 27, 2009, the inspectors were performing walkdowns of the

Unit 2 essential spray ponds and observed a high concentration of potential tornado

borne missile hazards within 400 feet of the essential spray ponds. The potential missile

hazards included stacks of pallets, temporary light fixtures, stanchions, scaffolding,

temporary structures, and other miscellaneous materials. The inspectors then notified

the Unit 2 shift manager of the potentially nonconforming condition.

The following morning on October 28, 2009, the inspectors observed an even higher

concentration of potential missile hazards including approximately 40 pallets stacked in

the immediate vicinity of the Unit 2 essential spray ponds. The inspectors notified civil

engineering personnel who then conducted a walkdown of the essential spray ponds for

Unit 2. PVAR 3397505 documented the walkdown and noted numerous areas of

noncompliance with Specification 13-CN-0389, Installations Specification for the Control

of Potential Tornado Borne Missiles in Outside Areas, Revision 0. Later that day

operations personnel reviewed PVAR 3397505 and requested civil engineering to

perform an evaluation of the areas surrounding the Unit 1 and Unit 2 essential spray

ponds to support an operability determination/functional assessment.

On the morning of October 29, 2009, the inspectors observed that the stack of pallets

and other miscellaneous potential missile hazards still had not been relocated or

secured in accordance with Specification 13-CN-0389. The inspectors noted that civil

engineering personnel conducted their review to ensure compliance and utilized

Procedure 81DP-0ZY01, "Control of Potential Tornado Borne Missiles in the Outside

Areas," Revision 3. The engineering evaluation was documented in Component

Observation Report 09-9-011. The evaluation concluded that while an excessive

number of temporary structures caused certain zones to exceed the maximum

- 17 - Enclosure 2

allowable average missile density of 4 per 10,000 square feet, the overall density across

all zones surrounding the Unit 1 and Unit 2 essential spray ponds was less than the

maximum allowable density. Based on this evaluation, operations personnel performed

an functional determination and declared the essential spray ponds for Units 1 and 2

functional.

The inspectors analyzed the civil engineering evaluation and concluded it accurately

represented the potential missile hazard density at the time of the evaluation. However,

in response to PVAR 3397505, maintenance personnel removed potential missile

hazards from within 400 feet of the spray ponds the morning of October 29, 2009. The

evaluation civil engineering personnel conducted on the afternoon of October 29, 2009

did not include at least 30 additional pallets that were within 400 feet of the Unit 2

essential spray ponds that the inspectors had photographed the day before. When the

inspectors shared these photographs with civil engineering personnel, the additional

pallets were included in a second evaluation, which concluded the maximum allowable

density of 4 missiles per 10,000 square feet across all zones surrounding the Unit 2

essential spray ponds was exceeded. At the time, Unit 2 was defueled as part of

Refueling Outage U2R15 and the Unit 2 essential spray ponds were not required to be

operable per technical specifications. However, they were being credited for spent fuel

pool cooling and therefore required to be Functional as defined by Section 5.1 of

Procedure 40DP-9OP26 Operations PVAR Processing and Operability

Determination/Functional Assessment, Revision 26.

During their review, the inspectors also noted that UFSAR, Section 3.5.1.4, "Missiles

Generated by Natural Phenomena (Tornados)," stated, in part, that tornado missile

protection is not provided for the essential spray pond nozzles because the probability of

loss of the ultimate heat sink safety function has been demonstrated by probabilistic risk

assessment to be less than a median value of 10-7 per reactor year or a mean value of

10-6 per reactor year without missile protection. The licensee ensured the probabilistic

risk assessment numbers provided in UFSAR Section 3.5.1.4 were satisfied by giving

recommended missile densities in Calculation 13-NC-SP-201, "Spray Pond Tornado

Missile Damage Frequency," Revision 3. To ensure the missile densities given in

calculation 13-NC-SP-201 were not exceeded, civil engineering personnel perform

quarterly walkdowns of the essential spray ponds, and rely on ensuring the requirements

of Procedure 81DP-0ZY01 and Specification 13-CN-0389 are implemented to control

transient missile hazards.

During their review, the inspectors noted a previous noncited violation

(NCV 05000528/2008004-04, Failure to Provide an Adequate Procedure to Control

Essential Spray Pond Missile Hazards) in NRC integrated inspection report 2008004 for

a similar performance deficiency identified July 11, 2008. The inspectors reviewed

corrective actions associated with that violation detailed in adverse CRDR 3224028 to

determine why the licensee failed to restore compliance within a reasonable time. The

inspectors noted that the corrective actions to restore compliance included revising

Procedure 30DP-09MP01 Conduct of Maintenance to add a step instructing

maintenance personnel to secure potential missile hazards in accordance with

Procedure 81DP-0ZY01. The corrective actions also included reviews of Procedure

81DP-0ZY01 and Procedure 12DP-0MC45 Management of Contracts and Supplier

Personnel, in which engineering personnel concluded that these procedures adequately

addressed the control of potential missile hazards around the essential spray ponds.

- 18 - Enclosure 2

Prior to NCV 05000528/2008004-04, the inspectors noted a noncited violation (NCV

05000528; 529; 530/2007012-01, Failure to Implement the Operability Determination

process) in NRC supplemental 95003 inspection report 2007012 discussed a similar

performance deficiency regarding potential missile hazards around the essential spray

ponds. In this case the performance deficiency was the failure of operations personnel

to perform an operability determination for an unanalyzed condition involving a high

concentration of potential missile hazards around the essential spray ponds. The

corrective actions identified by the licensee for this noncited violation were to enhance

Procedure 81DP-0ZY01 to include guidance for engineering personnel. Specifically, civil

engineering personnel were to ensure the essential spray ponds were evaluated for

missile hazard density when maintenance activities involving potential missile hazards

occurred.

On January 30, 2009, as part of the licensees internal corrective actions for non-cited

violations associated with the 95003 inspection, the licensee reviewed the treatment of

potential missile hazards and concluded that Procedure 81DP-0ZY01 was inadequate

for controlling missile hazards around the essential spray ponds. The licensee initiated

CRDR 3280781 and conducted an apparent cause evaluation to investigate and correct

the ineffective control of tornado-borne missile hazards. The inspectors noted that

corrective actions called for in the apparent cause evaluation included assigning

ownership to the areas surrounding the spray ponds, revising Procedure 81DP-0ZY01,

developing a site wide training plan for missile hazard control, and creating

Specification 13-CN-0389 to provide additional guidance for all personnel on control of

potential missile hazards. As an interim corrective action, civil engineering personnel

conducted monthly walkdowns of the areas surrounding the essential spray ponds from

April through September 2009. The inspectors observed that Specification 13-CN-0389

was completed on September 30, 2009; however, the revisions to Procedure

81DP-0ZY01 and the site wide training plan are not scheduled to be completed until

January 15, 2010.

After conducting several interviews with civil engineering personnel and reviewing all of

the corrective actions to address the missile hazards since the 95003 inspection, the

inspectors concluded that the licensee did not restore compliance and provide an

adequate procedure to control essential spray pond missile hazards within a reasonable

time. The inspectors noted that even if all transient missile hazards were secured in

accordance with step 8.7.4 of Specification 13-CN-0389, there was still the potential for

missile hazards to accumulate to densities greater than the acceptable limits allowed per

calculation 13-NC-SP-201 in the time periods between quarterly walkdowns. The

inspectors also noted that the licensee failed to implement adequate interim corrective

actions after determining that Procedure 81DP-0ZY01 was inadequate. Following the

completion of Specification 13-CN-0389, the inspectors noted procedures governing

housekeeping and conduct of maintenance still referenced Procedure 81DP-0ZY01 to

address the control of potential missile hazards. The inspectors also noted that

Procedure AC-0241, "Maintenance Work Order Process and Control," Revision 0, did

not address potential missile hazards when developing maintenance work packages nor

did Procedure 12DP-0MC45 Management of Contracts and Supplier Personnel directly

address informing contractor personnel of procedures for controlling potential missile

hazards. Based on the inspectors observations from October 27 through October 29,

2009, it was evident that neither maintenance nor contractor personnel had been

adequately trained on the control of potential missile hazards per Specification

13-CN-0389. Furthermore, the inspectors noted that neither Specification 13-CN-0389

- 19 - Enclosure 2

nor Procedure 81DP-0ZY01 provided adequate guidance on exactly when an observed

concentration of potential missile hazards merits an operability determination or

functional assessment for the essential spray ponds.

Analysis. The performance deficiency associated with this finding was the failure of

engineering personnel to establish adequate maintenance procedures to ensure

evaluation and approval of transient missile hazards that have an effect on the

operability of the essential spray ponds. The finding is more than minor because it is

associated with the external factors attribute of the Mitigating Systems Cornerstone and

affects the cornerstone objective of ensuring the reliability of systems that respond to

initiating events to prevent undesirable consequences. Using Manual Chapter 0609.04,

"Phase 1 - Initial Screening and Characterization of Findings," the finding was

determined to have very low safety significance (Green) because the finding did not

result in a loss of system safety function, an actual loss of safety function of a single train

for greater than its technical specification allowed outage time, or screen as potentially

risk significant due to a seismic, flooding, or severe weather initiating event. This finding

has a crosscutting aspect in the area of problem identification and resolution associated

with the corrective action program because appropriate corrective actions were not

taken to address safety issues and adverse trends in a timely manner, commensurate

with their safety significance and complexity P.1(d).

Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures

and Drawings," requires that activities affecting quality shall be prescribed by

instructions, procedures, or drawings, and shall be accomplished in accordance with

those instructions, procedures, and drawings. UFSAR, Section 3.5.1.4, "Missiles

Generated by Natural Phenomena (Tornados)," provided probabilistic risk assessment

criteria to ensure essential spray pond operability. Calculation 13-NC-SP-201 provided

missile density requirements to ensure the probabilistic risk assessment numbers in

UFSAR, Section 3.5.1.4 are met. Procedure 81DP-0ZY01 and Specification

13-CN-0389 implemented the control of transient missile hazards to ensure the missile

density requirements of calculation 13-NC-SP-201 are met. Contrary to the above,

between January 15, 1997, and October 27, 2009, the licensee failed to provide

adequate procedures to ensure evaluation and approval of transient missile hazards that

have an effect on the operability of the essential spray ponds. Specifically, civil

engineering personnel failed to develop an adequate procedure to verify missile density

criteria are not exceeded. This finding was of very low safety significance and was

entered into the licensee's corrective action program as PVAR 3397839. Due to the

licensees failure to restore compliance from the previous noncited violation NCV

05000528/2008004-04 within a reasonable time, this violation is being cited in a Notice

of Violation consistent with Section VI.A of the NRC Enforcement Policy: VIO 05000528;

05000529;05000530/2009005-01 Failure to Establish Adequate Procedures to Control

Potential Tornado Borne Missile Hazards Near the Essential Spray Ponds.

1R18 Plant Modifications (71111.18)

a. Inspection Scope

The inspectors reviewed the following temporary/permanent modifications to verify that

the safety functions of important safety systems were not degraded:

- 20 - Enclosure 2

• October 13, 2009, Unit 1, installation of jumpers for defective heated junction

thermocouples on the reactor vessel level monitoring system, train A and train B

The inspectors reviewed the temporary modification and the associated safety

evaluation screening against the system design bases documentation, including the

UFSAR and the technical specifications, and verified that the modification did not

adversely affect the system operability/availability. The inspectors also verified that the

installation was consistent with the modification documents and that configuration control

was adequate. Additionally, the inspectors verified that the temporary modification was

identified on control room drawings, appropriate tags were placed on the affected

equipment, and licensee personnel evaluated the effects on mitigating strategies during

implementation of emergency operating procedures.

These activities constitute completion of one temporary plant modification inspection

sample as defined in Inspection Procedure 71111.18-05.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors reviewed the following postmaintenance activities to verify that

procedures and test activities were adequate to ensure system operability and functional

capability:

• September 23, 2009, Unit 2, nitrogen to containment low pressure header

isolation valve corrective maintenance on indications

• October 28, 2009, Unit 2, emergency diesel generator B load sequencing relay

following corrective maintenance

• November 3, 2009, Unit 2, refuelling water tank to train B safety injection

following preventative maintenance

• November 11, 2009, Unit 2, atmospheric dump valve accumulators following

modification to the system

• November 16, 2009, Unit 3, Generrex regulator inverter 1 following corrective

maintenance to replace inverter

• November 27, 2009, Unit 2, safety injection tank 2A discharge check valve to

Loop 2A following corrective maintenance

• December 2, 2009, Unit 1, emergency diesel generator B underfrequency relay

corrective maintenance due to aged related degradation

• December 15, 2009, Units 1, 2, and 3, station blackout generator battery

following planned maintenance

- 21 - Enclosure 2

The inspectors selected these activities based upon the structure, system, or

component's ability to affect risk. The inspectors evaluated these activities for the

following (as applicable):

• The effect of testing on the plant had been adequately addressed; testing was

adequate for the maintenance performed

• Acceptance criteria were clear and demonstrated operational readiness; test

instrumentation was appropriate

The inspectors evaluated the activities against the technical specifications, the UFSAR,

10 CFR Part 50 requirements, licensee procedures, and various NRC generic

communications to ensure that the test results adequately ensured that the equipment

met the licensing basis and design requirements. In addition, the inspectors reviewed

corrective action documents associated with postmaintenance tests to determine

whether the licensee was identifying problems and entering them in the corrective action

program and that the problems were being corrected commensurate with their

importance to safety. Specific documents reviewed during this inspection are listed in

the attachment.

These activities constitute completion of eight postmaintenance testing inspection

samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities (71111.20)

a. Inspection Scope

Unit 2 Refueling Outage 2R15

The inspectors reviewed the outage safety plan and contingency plans for the Unit 2

refueling outage, conducted between October 3, 2009 and December 9, 2009, to confirm

that licensee personnel had appropriately considered risk, industry experience, and

previous site-specific problems in developing and implementing a plan that assured

maintenance of defense in depth. During the refueling outage, the inspectors observed

portions of the shutdown and cooldown processes and monitored licensee controls over

the outage activities listed below.

• Configuration management, including maintenance of defense in depth, is

commensurate with the outage safety plan for key safety functions and

compliance with the applicable technical specifications when taking equipment

out of service

• Clearance activities, including confirmation that tags were properly hung and

equipment appropriately configured to safely support the work or testing

- 22 - Enclosure 2

• Installation and configuration of reactor coolant pressure, level, and temperature

instruments to provide accurate indication, accounting for instrument error

• Status and configuration of electrical systems to ensure that technical

specifications and outage safety-plan requirements were met, and controls over

switchyard activities

• Monitoring of decay heat removal processes, systems, and components

• Verification that outage work was not impacting the ability of the operators to

operate the spent fuel pool cooling system

• Reactor water inventory controls, including flow paths, configurations, and

alternative means for inventory addition, and controls to prevent inventory loss

• Controls over activities that could affect reactivity

• Refueling activities, including fuel handling and sipping to detect fuel assembly

leakage

• Startup and ascension to full power operation, tracking of startup prerequisites,

walkdown of the drywell (primary containment) to verify that debris had not been

left which could block emergency core cooling system suction strainers, and

reactor physics testing

• Licensee identification and resolution of problems related to refueling outage

activities

Unit 3 Maintenance Outage 3M15A

The inspectors reviewed the outage risk management plan and contingency plans for

the Unit 3 maintenance outage, conducted between December 3, 2009 and December

5, 2009, to confirm that licensee personnel had appropriately considered risk, industry

experience, and previous site-specific problems in developing and implementing a plan

that assured maintenance of defense in depth.

• Configuration management, including maintenance of defense in depth, is

commensurate with the outage risk management plan for key safety functions

and compliance with the applicable technical specifications when taking

equipment out of service.

• Status and configuration of electrical systems to ensure that technical

specifications and outage safety-plan requirements were met, and controls over

switchyard activities.

• Monitoring of decay heat removal processes, systems, and components.

• Startup and ascension to full power operation and tracking of startup

prerequisites

- 23 - Enclosure 2

• Licensee identification and resolution of problems related to maintenance outage

activities.

These activities constitute completion of one refueling and one other outage inspection

samples as defined in Inspection Procedure 71111.20-05.

b. Findings

Introduction. A Green self-revealing noncited violation of Technical Specification 5.4.1.a,

Procedures, was identified for the failure of maintenance personnel to maintain

containment closure capability as required by Procedure 70DP-0RA01, Shutdown Risk

Assessments. Specifically, on October 8, 2009 maintenance personnel designated for

emergency closure of the containment equipment hatch left containment to attend a

safety briefing for more than 4-hours before they returned to perform their required

duties.

.

Description. Palo Verde, Unit 2, shutdown and commenced a refueling outage on

October 1, 2009. On October 7, 2009, the containment equipment hatch was opened to

allow for moving of large equipment and components in and out of containment.

Procedure 70DP-0RA01, Shutdown Risk Assessments, required that a trained

containment closure team be stationed at the equipment hatch to ensure the capability

to isolate containment within the RCS time to boil is maintained. The procedure credited

maintenance personnels ability to close the equipment hatch within 25 minutes.

On October 8, 2009, at approximately 8 p.m., maintenance crews working in

containment dropped a reactor vessel guide pin. Due to this event, at approximately

10:30 p.m., all maintenance personnel in containment were directed to stop work

pending a safety briefing to discuss the dropped guide pin. At 12:30 a.m. on

October 9, 2009, the team responsible for containment closure left containment to await

the safety briefing in a trailer near Unit 1. After the safety briefing, at 4:30 a.m., the

containment closure team returned to containment. Later that morning, at approximately

6 a.m., the inspectors discussed the event with operations personnel and determined

that while the containment equipment hatch closure team was removed from

containment, the ability to close the equipment hatch and isolate containment if needed

during a loss of shutdown cooling event was in question. During their review, the

inspectors reviewed logs and personal statements as well as reviewed timed simulations

and determined that the licensee would not have been able to return to containment and

close the equipment hatch within 30 minutes contrary to the requirements of Procedure

70DP-0RA01, Shutdown Risk Assessments.

Analysis. The performance deficiency associated with this finding involved the failure of

maintenance personnel to follow the requirements of Procedure 70DP-0RA01,

Shutdown Risk Assessments, to ensure a containment closure team was in

containment and capable of closing the containment equipment hatch within 30 minutes.

The finding was more than minor because it affected the configuration control attribute of

the Barrier Integrity Cornerstone, and affected the cornerstone objective to provide

reasonable assurance that physical design barriers protect the public from radionuclide

releases caused by accidents or events. Using Manual Chapter 0609.04, Phase 1 -

Initial Screening and Characterization of Findings," the finding was determined to

represent an actual open pathway in the physical integrity of reactor containment, and

required evaluation using Manual Chapter 0609, Appendix H, Containment Integrity

- 24 - Enclosure 2

Significance Determination Process. The finding was determined to be a Type B finding

because it affected only large early release frequency, not core damage frequency, at

shutdown. Using Manual Chapter 0609, Appendix H, Table 6.3, Phase 1 Screening-

Type B Findings at Shutdown, the inspectors determined that a Phase 2 evaluation was

required. The inspectors performed a Phase 2 analysis using Table 6.4, Phase 2 Risk

Significance-Type B Findings at Shutdown, and made the following determinations:

The plant was determined to be in POS 2E which represents cold shutdown with

the RCS vented, steam generators not available, and within 8 days of shutdown

The finding existed for less than 8-hours

There was mitigation equipment out of service

The inspectors reviewed Table 6.8, PWRs With In-Depth Shutdown Mitigation

Capability, and determined that during the time that Palo Verde lost the capability to

close the equipment hatch in less than 30 minutes, there was an in-depth shutdown

mitigation capability. The senior reactor analyst reviewed the analysis and determined

that that the finding has very low safety significance (Green). This was based on the

short time period that the condition existed (approximately 4-hours), the low probability

of a loss of cooling event during this period (two fully-functional trains were available),

and the fact that the time it would have taken to close the hatch in the worst case (30-

minutes) was well less than the time until the core would have become uncovered

(greater than 60-minutes), indicating that the probability of failing to close the equipment

hatch prior to fuel damage was very low. This finding was determined to have a cross

cutting aspect in the area of human performance associated with work control because

the licensee failed to appropriately coordinate work activities by incorporating actions to

address plant conditions that may affect work activities H.3(b).

Enforcement. Palo Verde Technical Specification 5.4.1.a, Procedures, requires that

written procedures be established, implemented, and maintained covering the activities

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

Regulatory Guide 1.33, Appendix A, Section 3.f.(1), requires, in part, that during

shutdown operations, procedures shall be prepared for maintaining containment

integrity. Procedure 70DP-0RA01, Shutdown Risk Assessments, Revision 32,

required, in part, that a trained containment closure team shall be stationed inside

containment and shall be capable of closing the containment equipment hatch within the

RCS time to boil (30 minutes). Contrary to the above, on October 8, 2009, maintenance

personnel dedicated for the emergency closure of the containment equipment hatch left

containment and were unable to perform their containment equipment hatch closure

function within the reactor coolant system time to boil. Because the finding is of very low

safety significance and has been entered into the licenses corrective action program as

PVAR 3389284 this violation is being treated as a noncited violation consistent with

section VI.A of the NRC Enforcement Policy: NCV 05000529/2009005-02 Failure to

Maintain Containment Closure Capability.

- 25 - Enclosure 2

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and technical

specifications to ensure that the three surveillance activities listed below demonstrated

that the systems, structures, and/or components tested were capable of performing their

intended safety functions. The inspectors either witnessed or reviewed test data to verify

that the significant surveillance test attributes were adequate to address the following:

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Updating of performance indicator data

• Engineering evaluations, root causes, and bases for returning tested systems,

structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

• Annunciators and alarms setpoints

The inspectors also verified that licensee personnel identified and implemented any

needed corrective actions associated with the surveillance testing.

• October 23, 2009, Unit 2, essential spray pond pumps train B - comprehensive

and inservice pump test

• October 30, 2009, Unit 1, safety injection system train B valve stroke tests

• December 1, 2009, Unit 2, low power physics testing

Specific documents reviewed during this inspection are listed in the attachment.

- 26 - Enclosure 2

These activities constitute completion of three surveillance testing inspection samples as

defined in Inspection Procedure 71111.22-05.

b. Findings

No findings of significance were identified.

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 licensee=s performance in implementing physical

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

radiation areas, and worker adherence to these controls with respect to the Unit 2

refueling outage and reactor vessel head replacement activities. The inspectors used

the requirements in 10 CFR Part 20, the technical specifications, and the licensee=s

procedures required by technical specifications as criteria for determining compliance.

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

radiation protection supervisors, and radiation workers. The inspectors performed

independent radiation dose rate measurements and reviewed the following items:

• Controls (surveys, posting, and barricades) of five radiation, high radiation, and

potential airborne radioactivity areas

• Radiation exposure permit, procedure, and 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

• Adequacy of the licensees internal dose assessment for any actual internal

exposure greater than 50 mrem committed effective dose equivalent

• Barrier integrity and performance of engineering controls in 4 potential airborne

radioactivity areas

• Radiation exposure permit briefings and worker instructions

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

job coverage, and contamination controls during job performance

• Dosimetry placement in high radiation work areas with significant dose rate

gradients

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

areas during certain plant operations

- 27 - Enclosure 2

• 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

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three of the required 21 samples as defined in

Inspection Procedure 71121.01-05. The remaining samples in Inspection Procedure

71121.01 were previously documented in NRC Integrated Inspection Report 05000528;

05000529; 05000530/2009003.

b. Findings

Introduction. A self-revealing Green noncited violation of Technical Specification 5.7.1,

High Radiation Areas, was identified for the failure of radiological protection personnel

to perform a prejob briefing to ensure workers are aware of radiological conditions in a

high radiation area as required by the radiation exposure permit. Specifically, on

October 20, 2009, nine contract workers were preparing to install an anticontamination

sock over the Unit 2 old reactor vessel head, signed onto a radiation exposure permit

which allowed access to a high radiation area but failed to receive a brief on the local

dose rates surrounding the reactor vessel head by the job coverage radiation protection

technician.

Description. On October 20, 2009, nine contractor workers were preparing to install an

anticontamination sock over the Unit 2 old reactor vessel head. The workers signed

onto a radiation exposure permit which allowed access to a high radiation area (the

entire area around the vessel head was being controlled as a high radiation area). The

contractors entered the radiological controlled area, dressed out, and entered

containment after receiving a briefing from the radiation protection technician on

containment radiation levels. However, they did not receive a prejob brief on dose rates

from radiation protection technician covering the reactor vessel head job as required by

the radiation exposure permit. They proceeded to cover the vessel head, but one

worker received an 85 mr/hr electronic dosimeter rate alarm. Based on the alarm

investigation, it was revealed that none of the nine workers had received the required

prejob briefing from a radiation protection technician making them aware of the 100- to

140-mr/hr dose rate levels in the high radiation area. Trip tickets had not been signed by

the radiation protection technician covering the job; therefore, they were not authorized

to enter the high radiation area. The licensees immediate corrective action was to

counsel the contractor group and radiation protection staff on prejob briefing

expectations.

Analysis. The performance deficiency associated with this finding was the failure of the

licensee to comply with high radiation area entry requirements and perform radiation

exposure permit prejob briefs. The finding was more than minor because it was

associated with the exposure control attribute of the Occupational Radiation Safety

Cornerstone and affected the cornerstone objective to properly control access to a high

radiation area and had the potential to increase personnel dose. Using Manual Chapter

0609, Appendix C, Occupational Radiation Safety Significance Determination Process,

- 28 - Enclosure 2

the finding was determined to have very low safety significance (Green) because it was

not associated with as low as reasonably achievable, there was no overexposure,

there was no substantial potential for an overexposure; and the ability to assess dose

was not compromised. This finding has a crosscutting aspect in the area of human

performance associated with work practices because the licensees radiation protection

staff failed to communicate expectations to contract personnel H.4(b).

Enforcement. Technical Specification 5.7.1, High Radiation Areas, requires that entry

into high radiation areas shall be controlled by requiring issuance of a radiation exposure

permit. Contrary to the above, on October 20, 2009, nine contractors entered a high

radiation area not in accordance with the radiation exposure permit. Specifically, they

entered the high radiation area without receiving a pre-briefing and without being made

aware of the dose rates in the area. This failure to meet high radiation area entry

requirements is of very low safety significance and has been entered into the licensees

corrective action program as CRDR 3394172. This violation is being treated as a

noncited, consistent with Section VI.A of the NRC Enforcement Policy: NCV

05000529/2009005-03, Failure to Comply with High Radiation Area Entry

Requirements.

2OS2 ALARA Planning and Controls (71121.02)

a. Inspection Scope

The inspectors assessed licensee performance with respect to maintaining individual

and collective radiation exposures As Low As Reasonably Achievable (ALARA). The

inspectors used the requirements in 10 CFR Part 20 and the licensees procedures

required by technical specifications as criteria for determining compliance. The

inspectors interviewed licensee personnel and reviewed:

• Current 3-year rolling average collective exposure

• Site-specific trends in collective exposures, plant historical data, and source-term

measurements

• Site-specific ALARA procedures

• Five work activities of highest exposure significance completed during the last

outage

• ALARA work activity evaluations, exposure estimates, and exposure mitigation

requirements

• Intended versus actual work activity doses and the reasons for any

inconsistencies

• Interfaces between operations, radiation protection, maintenance, maintenance

planning, scheduling and engineering groups

• Integration of ALARA requirements into work procedure and radiation exposure

permit documents

- 29 - Enclosure 2

• Person-hour estimates provided by maintenance planning and other groups to

the radiation protection group with the actual work activity time requirements

• Shielding requests and dose/benefit analyses

• Dose rate reduction activities in work planning

• Post-job (work activity) reviews

• Assumptions and basis for the current annual collective exposure estimate, the

methodology for estimating work activity exposures, the intended dose outcome,

and the accuracy of dose rate and man-hour estimates

• Method for adjusting exposure estimates, or replanning work, when unexpected

changes in scope or emergent work were encountered

• Exposure tracking system

• Use of engineering controls to achieve dose reductions and dose reduction

benefits afforded by shielding

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

a dose efficient manner

• Records detailing the historical trends and current status of tracked plant source

terms and contingency plans for expected changes in the source term due to

changes in plant fuel performance issues or changes in plant primary chemistry

• Source-term control strategy or justifications for not pursuing such exposure

reduction initiatives

• Specific sources identified by the licensee for exposure reduction actions,

priorities established for these actions, and results achieved since the last

refueling cycle

• 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

postjob 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

Specific documents reviewed during this inspection are listed in the attachment.

- 30 - Enclosure 2

The inspectors completed 13 of the required 15 samples and 12 of the optional samples

as defined in Inspection Procedure 71121.02-05.

b. Findings

Introduction. The inspectors identified a noncited violation of 10 CFR Part 50.71,

Maintenance of Records, because the licensee failed to update their UFSAR with

submittals that include the effects of a change made to the facility. Specifically, the

licensee built the old steam generator storage facility on the owner controlled area for

long-term radwaste storage of six decommissioned steam generators and three reactor

vessel heads and failed to update the UFSAR to include these changes to the facility

and all safety analyses and evaluations performed.

Description. While inspecting the licensees Unit 2 reactor head replacement activities

related to solid radwaste management and storage, the inspectors identified that the

decommissioned steam generator and reactor vessel head storage facility was not

described in Chapters 11 and 12 of the UFSAR. Currently, the UFSAR, Chapters 11

and 12, Sections 11.4, Solid Waste Management, and 12.2.1.7, "Stored Radioactivity,"

describes facilities for the interim storage of radioactive material such as the dry active

waste processing and storage facility and the low level radioactive material storage

facility. However, the old steam generator storage facility is not described in the

UFSAR. Section 12.2.1.7 of the UFSAR also describes that principal sources of

radioactivity not enclosed by plant structures are the independent spent fuel storage

installation, the refueling water tank, the holdup tank, the reactor makeup water tank,

and the condensate storage tank.

The licensee is committed to Regulatory Guide 1.70, Standard, Format, and Content of

a Safety Analysis Report, Revision 3, which describes the content of Chapter 11,

Section 11.4, Solid Waste Management System. Regulatory Guide 1.70 states, in part,

that this section should describe the capabilities of the plant to control, collect, handle,

process, package, and temporarily store prior to shipment wet and dry solid radioactive

waste generated as a result of normal operation, including anticipated operational

occurrences. Regulatory Guide 1.70 also describes Chapter 12 of a safety analysis

report stating, in part, that it should provide information on methods for radiation

protection, estimated occupational radiation exposures to personnel during normal

operation and anticipated operational occurrences including radioactive material

handling, processing, use, and storage. Section 12.2.1, Radiation Contained Sources,

is the basis for the radiation protection design that should be described in the manner

needed as input to the shield design calculations. Those sources that are contained in

equipment like the radioactive waste management systems should be described. The

source location in the plant should be specified so that all important sources of

radioactivity can be located on plant layout drawings. Also, the safety analysis report

should provide a listing of isotope, quantity, form, and use of all sources that exceed 100

millicuries.

The old steam generator storage facility has been in use since 2003 and contains six

decommissioned steam generators from Units 1, 2, and 3 and now the Unit 2 reactor

vessel head. Each old steam generator contains 48.1 curies of Co-60 and the reactor

head contains 7.5 curies Co-60. Thus, the old steam generator storage facility contains

296 curies, a significant source of radioactivity, not described in the licensees UFSAR.

- 31 - Enclosure 2

Analysis. The performance deficiency associated with this finding was failure of the

licensee to update the UFSAR to reflect changes made to the facility. This issue was

dispositioned using traditional enforcement because it had the potential for impacting the

NRCs ability to perform its regulatory function. The finding is more than minor because

it has a material impact on licensed activities in that the six decommissioned steam

generators and the Unit 2 reactor vessel head, with a significant radioactive source term,

have been relocated from the plant radiological controlled area to the owner controlled

area. In addition, the radwaste management program has been affected because the

licensee determined that this low-level radwaste facility will store these large

components until the site is decommissioned. The finding is characterized as a Severity

Level IV, noncited violation in accordance with NRC Enforcement Policy, Supplement I,

and was treated as a noncited violation consistent with Section VI.A.1 of the NRC

Enforcement Policy. This finding was reviewed for crosscutting aspects and none were

identified because the performance deficiency is not indicative of current performance.

Enforcement. Title 10 CFR 50.71, Maintenance of Records, requires, in part, that

licensees periodically update their UFSAR with submittals that include the effects of all

changes made in the facility or procedures as described in the UFSAR, and all safety

analyses and evaluations performed by the licensee in support of conclusions that

changes did not require a license amendment in accordance with 10 CFR 50.59(c)(2).

Contrary to this requirement, from 2003 through the present, the licensee made changes

to the facility and procedures as described in the UFSAR performed safety analyses and

evaluations in support of these changes, but failed to update the UFSAR to include

these changes. Specifically, the licensee built the old steam generator storage facility

for storing radioactive waste (six replaced steam generators and three reactor vessel

heads) on the owner controlled site for long-term storage until decommissioning.

Because the finding was of very low safety significance and has been entered into

licensee corrective action program as CRDR 3398042, this violation is being treated as

an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000528;

05000529;05000530/2009005-04, Failure to Periodically Update the UFSAR.

4. OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

.1 Data Submission Issue

a. Inspection Scope

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

quarter 2009 performance indicators for any obvious inconsistencies prior to its public

release in accordance with Inspection Manual Chapter 0608, Performance Indicator

Program.

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

as such, did not constitute a separate inspection sample.

b. Findings

No findings of significance were identified.

- 32 - Enclosure 2

.2 Mitigating Systems Performance Index - Auxiliary Feedwater System

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance

index for Units 1, 2, and 3 - auxiliary feedwater system performance indicator for the

period from the fourth quarter 2008 through the third quarter 2009. To determine the

accuracy of the performance indicator data reported during those periods, performance

indicator definitions and guidance contained in NEI Document 99-02, Regulatory

Assessment Performance Indicator Guideline, Revision 5, was used. The inspectors

reviewed the licensees operator narrative logs, issue reports, event reports, mitigating

systems performance index derivation reports, and NRC integrated inspection reports for

the period of October 1, 2008 through September 30, 2009, to validate the accuracy of

the submittals. The inspectors reviewed the mitigating systems performance index

component risk coefficient to determine if it had changed by more than 25 percent in

value since the previous inspection, and if so, that the change was in accordance with

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

database to determine if any problems had been identified with the performance

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

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three mitigating systems performance index

heat removal system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.3 Mitigating Systems Performance Index - Residual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance

index - residual heat removal system performance indicator for the period from the fourth

quarter 2008 through the third quarter 2009. To determine the accuracy of the

performance indicator data reported during those periods, performance indicator

definitions and guidance contained in NEI Document 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 5, was used. The inspectors reviewed the

licensees operator narrative logs, issue reports, mitigating systems performance index

derivation reports, event reports and NRC integrated inspection reports for the period of

October 1, 2008 through September 30, 2009, to validate the accuracy of the submittals.

The inspectors reviewed the mitigating systems performance index component risk

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

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

guidance. The inspectors also reviewed the licensees issue report database to

determine if any problems had been identified with the performance indicator data

collected or transmitted for this indicator and none were identified. Specific documents

reviewed during this inspection are listed in the attachment.

These activities constitute completion of three mitigating systems performance index

residual heat removal systems sample as defined in Inspection Procedure 71151-05.

- 33 - Enclosure 2

b. Findings

No findings of significance were identified.

.4 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance

index - cooling water systems performance indicator for the period from the fourth

quarter 2008 through the third quarter 2009. To determine the accuracy of the

performance indicator data reported during those periods, performance indicator

definitions and guidance contained in NEI Document 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 5, was used. The inspectors reviewed the

licensees operator narrative logs, issue reports, mitigating systems performance index

derivation reports, event reports and NRC integrated inspection reports for the period of

October 1, 2008 through September 30, 2009, to validate the accuracy of the submittals.

The inspectors reviewed the mitigating systems performance index component risk

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

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

guidance. The inspectors also reviewed the licensees issue report database to

determine if any problems had been identified with the performance indicator data

collected or transmitted for this indicator and none were identified. Specific documents

reviewed are described in the attachment to this report.

These activities constitute completion of three mitigating systems performance index

cooling water system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.5 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the radiological effluent technical

specifications/offsite dose calculation manual radiological effluent occurrences

performance indicator for the period from the first quarter 2009 through third quarter

2009. To determine the accuracy of the performance indicator data reported during

those periods, performance indicator definitions and guidance contained in NEI

Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5,

was used. The inspectors reviewed the licensees issue report database since this

indicator was last reviewed to identify any potential occurrences such as unmonitored,

uncontrolled, or improperly calculated effluent releases that may have impacted offsite

dose. Additionally, the inspectors reviewed the licensees historical 10 CFR 50.75(g) file

and selectively reviewed the licensees analysis for discharge pathways resulting from a

spill, leak, or unexpected liquid discharge focusing on those incidents which occurred

over the last few years.

- 34 - Enclosure 2

These activities constitute completion of the radiological effluent technical

specifications/offsite dose calculation manual radiological effluent occurrences sample

as defined by Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency

Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical

Protection

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of

this report, the inspectors routinely reviewed issues during baseline inspection activities

and plant status reviews to verify that they were being entered into the licensees

corrective action program at an appropriate threshold, that adequate attention was being

given to timely corrective actions, and that adverse trends were identified and

addressed. The inspectors reviewed attributes that included: the complete and

accurate identification of the problem; the timely correction, commensurate with the

safety significance; the evaluation and disposition of performance issues, generic

implications, common causes, contributing factors, root causes, extent of condition

reviews, and previous occurrences reviews; and the classification, prioritization, focus,

and timeliness of corrective actions. Minor issues entered into the licensees corrective

action program because of the inspectors observations are included in the attached list

of documents reviewed.

These routine reviews for the identification and resolution of problems did not constitute

any additional inspection samples. Instead, by procedure, they were considered an

integral part of the inspections performed during the quarter and documented in

Section 1 of this report.

b. Findings

No findings of significance were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific

human performance issues for follow-up, the inspectors performed a daily screening of

items entered into the licensees corrective action program. The inspectors

accomplished this through review of the stations daily corrective action documents.

- 35 - Enclosure 2

The inspectors performed these daily reviews as part of their daily plant status

monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings of significance were identified.

.3 Selected Issue Follow-up Inspection

a. Inspection Scope

In addition to the routine review, the inspectors selected the below listed issue 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.

• November 20, 2009, verification of siren coverage for the emergency planning

zone as required by the PVNGS emergency plan

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one in-depth problem identification and

resolution sample as defined in Inspection Procedure 71152-05.

b. Findings

No findings of significance were identified.

.4 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees corrective action program and

associated documents to identify trends that could indicate the existence of a more

significant safety issue. The inspectors focused their review on repetitive equipment

issues, but also considered the results of daily corrective action item screening

discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human

performance results. The inspectors nominally considered the 6-month period of July 1

through December 31, 2009, although some examples expanded beyond those dates

where the scope of the trend warranted.

The inspectors also included issues documented outside the normal corrective action

program in major equipment problem lists, repetitive and/or rework maintenance lists,

departmental problem/challenges lists, system health reports, quality assurance

audit/surveillance reports, self-assessment reports, and maintenance rule assessments.

The inspectors compared and contrasted their results with the results contained in the

licensees corrective action program trending reports. Corrective actions associated with

- 36 - Enclosure 2

a sample of the issues identified in the licensees trending reports were reviewed for

adequacy.

These activities constitute completion of one single semi-annual trend review inspection

sample as defined in Inspection Procedure 71152-05.

b. Findings

No findings of significance were identified.

.5 In-depth Review of Operator Workarounds

a. Inspection Scope

The inspectors conducted a cumulative review of operator workarounds for Units 1, 2,

and 3 and assessed the effectiveness of the operator workaround program to verify that

the licensee is: (1) identifying operator workaround problems at an appropriate

threshold; (2) entering them into the CAP; and (3) identifying and implementing

appropriate corrective actions. The review included walkdowns of the control room

panels, interviews with licensed operators and reviews of the control room discrepancies

log, the lit annunciators log, the operator workaround list, the operator burdens list,

operations concerns list, the operator challenges tracking system, and site performance

metrics for operator burdens, lit annunciators, control room discrepancies, and long term

tagouts.

These activities constitute completion of one operator workaround program inspection

sample as defined in Inspection Procedure 71152-05.

b. Findings and Observations

No findings of significance were identified.

4OA3 Event Follow-up (71153)

.1 Event Follow Up

a. Inspection Scope

The inspectors reviewed the two events listed below for plant status and mitigating

actions to: (1) provide input in determining the appropriate agency response in

accordance with Management Directive 8.3, NRC Incident Investigation Program;

(2) evaluate licensee actions; and (3) confirm that the licensee properly classified the

event in accordance with emergency action level procedures and made timely

notifications to NRC and state/governments, as required.

• December 3, 2009, Unit 3, manual reactor trip from 100 percent power on a loss

of instrument air to containment

• December 10, 2009, Unit 2, downpower to support emergent repairs on the main

transformer train C neutral bushing

- 37 - Enclosure 2

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two samples as defined in Inspection

Procedure 71153-05.

b. Findings

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

Criterion V, "Instructions, Procedures, and Drawings," was identified for the failure of

operations personnel to adequately establish and implement procedures associated with

a loss of instrument air to containment. Specifically, on December 3, 2009, the alarm

response and abnormal operating procedures available to the Unit 3 control room

operating staff were inadequate to effectively diagnose and mitigate a loss of instrument

air to containment.

Description. On December 3, 2009, Unit 3 was operating at full power. At

approximately 3:20 a.m. a ground alarm was received for the 125 Vdc electrical bus

E-PKA-M41. The control room crew entered panel B01A alarm response Procedure

43AL-3RK1A and dispatched an area operator to the 125 Vdc electrical bus in question.

At approximately 3:29 a.m. the area operator reset the ground alarm. At 3:39 a.m., a

high pressure alarm was received for the reactor coolant pump control bleed-off and the

crew recognized that control bleed-off isolation to the volume control tank valve

CHA-UV-506 position was intermediate and subsequently closed approximately one

minute later. The crew determined that the control bleed-off would be redirected to the

reactor drain tank via the system relief valve. The crew then entered panel B03A alarm

response Procedure 40AL-9RK3A to address the control bleed-off high pressure

condition. At approximately 3:48 a.m. a high level alarm was received for the reactor

drain tank level being greater than 75 percent, and at 3:54 a.m., a reactor drain tank high

pressure alarm was received. During an attempt to pump down the reactor drain tank

the crew discovered that valve CHA-UV-560, the reactor drain tank isolation inside

containment, was closed and would not reopen. At approximately 4:05 a.m., the crew

identified Valve IAA-UV-002, the isolation for instrument air to the containment, was

without indication and diagnosed a loss of instrument air to the containment.

The crew entered Procedure 40AO-9ZZ06, Loss of Instrument Air, and manually

tripped the reactor at 4:31 a.m. and secured all four reactor coolant pumps at 4:32 a.m.

Control bleed-off was isolated from the reactor coolant pumps at 4:34 a.m. The crew

entered Procedure 40EP-9EO07, Loss of Offsite Power/Loss of Forced Circulation, at

4:41 a.m. due to the loss of forced circulation when all the reactor coolant pumps were

secured. The decision to trip the reactor and secure all the reactor coolant pumps and

their associated control bleed-off was based on the desire to terminate the addition of

reactor coolant to the reactor drain tank. This would prevent rupturing the reactor drain

tank blow out disc. It was subsequently determined that the source of the previous

ground was a short circuit in the solenoid operator for IAA-UV-002. The short circuit is

believed to have cleared when the fuse in the circuit blew, causing a loss of power to

valve IAA-UV-002 resulting in the valve closing. A loss of instrument air to the

containment resulted when valve IAA-UV-002 closed.

Alarm response Procedure 43AL-3RK1A, 125V 1E CC M41 CHGR A/AC PNL D21

TRBL, addressed the ground indication received at 3:20 a.m. This procedure

implemented ground isolation steps but did not reference specific loads on panel

- 38 - Enclosure 2

PKA-M41. In addition, since the ground cleared and was subsequently reset when the

in-line fuse blew, no attempt to identify the source of the ground was made. Alarm

response Procedure 40AL-9RK3A, RCP SEAL SYS TRBL, entered at 3:39 a.m.,

directed determining the position of control bleed-off isolation valves CHB-UV-505 and

CHA-UV-506 and to reopen if closed. Alarm response Procedure 40AL-9RK3A,

RCP CONT BLEED-OFF PRESS HI-HI, also provided direction to determine if these

valve changed position and to reopen if closed, and directed investigating the cause of

their closure. The inspectors noted neither Procedure referenced a loss of instrument air

as a potential cause for their closure. At 3:48 a.m., alarm response Procedure 40AL-

9RK3A, REAC DRN LOOP TRBL, was entered for the reactor drain tank level of

greater than 75 percent. The crew recognized that the associated containment isolation

valve CHA-UV-560 was closed but did not associate its closure to a loss of instrument

air. At 4:05 a.m. a control room operator observed IAA-UV-002 without indication and

the loss of instrument air to the containment was subsequently diagnosed.

Procedure 40AO-9ZZ06, Loss of Instrument Air, provided guidance to reopen

IAA-UV-002 if instrument air is lost to the containment. Step 4 of this procedure

provided direction to perform Appendix J, Aligning N2 to the CTMT Instrument Air

Header, if IAA-UV-002 cannot be reopened. Step 7 of Procedure 40AO-9ZZ06 directed

the crew to perform Appendix A, Expected Component Failure as System Pressure

Drops. This appendix, page 11 of 36, indicated that the containment isolation valves for

the reactor coolant pump bleed-off to the volume control tank will close when

containment instrument air pressure drops to between 38 psig and 48 psig.

During their review, the inspectors noted this procedure directed these valves to be

manually opened if the reactor drain tank level is greater than 75 percent and the

containment is accessible. The reactor drain tank outlet isolation valves close in this

same pressure band. The inspectors also noted Procedure 40AO-9ZZ06, Appendix A,

was organized by component failures as overall instrument air header pressure drops

from the normal value but it did not differentiate containment instrument air header

pressure from the system instrument air header pressure. In addition, Appendix A did

not prioritize relative importance of each component failure nor did the procedure

address time constraints or industrial safety concerns for containment entries. The

appendix did not offer alternate strategies if the air operated valves cannot be reopened

in a timely manner. In addition, the inspectors noted Appendix J required resources for

a containment entry to restore instrument air header pressure inside containment. The

body of Procedure 40AO-9ZZ06, Loss of Instrument Air, did not prioritize actions

should the resources for containment entries be limited. With no success path provided

by existing procedures, the control room supervisor decided to take the unit off line, trip

the reactor coolant pumps, and isolate control bleed-off. The inspectors also noted that

removing the reactor coolant pumps from service and isolating control bleed-off were not

directed in the loss of instrument air abnormal operating procedure.

Analysis. The performance deficiency associated with this finding involved the failure of

operations personnel to adequately establish and implement abnormal operating

procedures associated with a loss of instrument air to the containment. The finding is

greater than minor because it is associated with the procedure quality attribute of the

Initiating Events Cornerstone and affects the cornerstone objective of limiting the

likelihood of those events that upset plant stability and challenge critical safety functions

during shutdown as well as power operations. Using the Manual Chapter 0609,

"Significance Determination Process," Phase 1 Worksheets, the finding was determined

- 39 - Enclosure 2

to have very low safety significance (Green) because the finding did not contribute to

both the likelihood of a reactor trip and the likelihood that mitigation equipment or

functions will not be available. This finding has a crosscutting aspect in the area of

problem identification and resolution associated with the corrective action program

because the licensee failed to implement the corrective action program with a low

threshold for identifying issues P.1(a).

Enforcement. 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and

Drawings," states, in part, that activities affecting quality shall be prescribed by

documented instructions, procedures, or drawings, of a type appropriate to the

circumstances and shall be accomplished in accordance with these instructions,

procedures, or drawings. Contrary to the above, procedures used to respond to the loss

of instrument air to the containment on December 3, 2009 were inadequate to effectively

diagnose and mitigate the off normal event. However, because the finding is of very low

safety significance and has been entered into the licensee's corrective action program as

PVAR 3411138 and CRDR 3411457, this violation is being treated as an NCV consistent

with Section VI.A of the NRC Enforcement Policy: NCV 05000528; 05000529;05000530/2009005-05, Inadequate Procedures to Diagnose and Mitigate a Loss of

Instrument Air to the Containment.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period the inspectors conducted observations of security force

personnel and activities to ensure that the activities were consistent with licensee

security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspectors observations of security force personnel and

activities did not constitute any additional inspection samples. Rather, they were

considered an integral part of the inspectors' normal plant status reviews and inspection

activities.

b. Findings

No findings of significance were identified.

.2 Temporary Instruction 2515-172, Reactor Coolant System Dissimilar Metal Butt Welds

a. Inspection Scope

Portions of Temporary Instruction 2515/172, Reactor Coolant System Dissimilar Metal

Butt Welds, were performed at PVNGS, Unit 2, during Refueling Outage U2R15.

Specific documents reviewed during this inspection are listed in the attachment. This

unit has the following dissimilar metal butt welds.

- 40 - Enclosure 2

• Two 12-inch pressurizer surge line nozzles, one each on the pressurizer and hot leg

sides were mitigated during Refueling Outage U2R14 using a weld overlay process,

and both were categorized as Category F following the weld overlay process

• Four 8-inch pressurizer safety nozzles were mitigated during Refueling Outage

U2R14 using a weld overlay process, and all were categorized as Category F

after the weld overlay

• Two 16-inch shutdown cooling nozzles were mitigated during Refueling Outage

U2R14 using a weld overlay process, and both were categorized as Category F

after the weld overlay

• Four 14-inch safety injection nozzles had ultrasonic examinations during

Refueling Outage U2R15 and all were categorized as Category E

• One 4-inch pressurizer spray nozzle and two 3-inch pressurizer spray nozzles

had bare metal visual examinations during Refueling Outage U2R14, no

mitigation was performed on the two 3-inch nozzles, and both categorized as

Category K. The 4-inch nozzle was mitigated using a weld overlay process

during Refueling Outage U2R14, and was categorized as Category F

• Three 2-inch drain line nozzles had bare metal visual examinations during

Refueling Outage U2R14, no mitigation was performed, and both were

categorized as Category K

• Two additional 2-inch line nozzles, one for letdown and one for charging, had

bare metal visual examinations during Refueling Outage U2R14, no mitigation

was performed, and both were categorized as Category K

i. Licensees Implementation of the Materials Reliability Program (MRP-139)

Baseline Inspections

(a) The inspectors reviewed records of structural weld overlays and

nondestructive examination activities associated with the licensees

pressurizer and hot leg structural weld overlay mitigation effort. The

baseline inspections of the pressurizer dissimilar metal butt welds were

completed during the spring 2008 Refueling Outage U2R14.

(b) At the present time, the licensee is not planning to take any deviations

from the baseline inspection requirements of MRP-139, and all other

applicable dissimilar metal butt welds are scheduled in accordance with

MRP-139 guidelines.

ii. Volumetric Examinations

(a) The inspectors reviewed the four ultrasonic examination records of the

unmitigated safety injection nozzles. The inspectors concluded that the

ultrasonic examination for these welds was done in accordance with

ASME Code,Section XI, Supplement VIII Performance Demonstration

Initiative, requirements regarding personnel, procedures, and equipment

- 41 - Enclosure 2

qualifications. No relevant conditions were identified during these

examinations.

(b) The inspectors reviewed the nondestructive evaluations performed on the

four safety injection nozzles. Inspection coverage met the requirements

of MRP-139 and no relevant conditions were identified.

(c) The certification records of examination personnel were reviewed for

those personnel that performed the examinations of the mitigated

nozzles. All personnel records showed that they were qualified under the

EPRI performance demonstration Initiative.

(d) No deficiencies were identified during the nondestructive evaluations.

iii. Weld Overlays

The licensee performed all weld overlays during the previous outage (2R14).

iv. Mechanical Stress Improvement

The licensee did not employ a mechanical stress improvement process.

v. Inservice Inspection Program

The licensees MRP-139 program is part of their alloy 600 program and future

inspections are in accordance with the MRP-139 requirements.

b. Findings

No findings of significance were identified.

.3 Reactor Vessel Head Replacement Inspection (71007)

.3.1 Design and Planning Inspections

a. Inspection Scope

The inspectors used the guidance in Inspection Procedure 71007 to perform the

following reactor vessel head design and planning inspection activities.

i. Engineering and Technical Support

Inspections were conducted by resident and regional office-based specialist

inspectors to review engineering and technical support activities performed prior

to, and during, the reactor vessel head replacement outage. This review verified

that selected design changes and modifications to structures, systems, and

components described in the UFSAR for transporting the new and old reactor

vessel heads were reviewed in accordance with 10 CFR Part 50.59. Additionally,

key design aspects and modifications associated with the reactor vessel head

replacement were also reviewed. Finally, the inspectors determined if the

licensee had confirmed that the existing reactor vessel head conformed to design

- 42 - Enclosure 2

requirements and that there were no fabrication deviations from design

requirements.

ii. Lifting and Rigging

The inspectors reviewed engineering design, modification, and analysis

associated with reactor vessel head lifting and rigging activities. This included:

(1) crane and rigging equipment; (2) reactor vessel head component drop

analysis; (3) safe load paths; and (4) load lay-down areas.

iii. Radiation Protection

The inspectors reviewed radiation protection program controls, planning, and

preparation in: (1) ALARA planning; (2) dose estimates and tracking;

(3) exposure and contamination controls; (4) radioactive material management;

(5) radiological work plans and controls; (6) emergency contingencies; and

(7) project staffing and training plans. This review was performed as part of the

baseline inspections conducted during the 2R15 outage and additional

information is documented in Section 2OS2 of this report.

b. Findings

No findings of significance were identified.

.3.2 Reactor Vessel Head Fabrication Inspections at Licensee Facility

a. Inspection Scope

The inspectors used the guidance in Inspection Procedure 71007 to perform the

following reactor vessel head fabrication inspection activities.

i. Heat Treatment

The inspectors verified that the material heat treatment used to enhance the

mechanical properties of the reactor vessel head material carbon, low alloy, and

high alloy chromium steels was conducted per ASME Code and approved vendor

procedures consistent with the applicable ASME Code,Section III requirements.

Also, inspections were performed to verify that adequate heat treatment

procedures were available to assure that the following requirements were met:

(1) furnace atmosphere; (2) furnace temperature distribution and calibration of

measuring and recording devices; (3) thermocouple installation; (4) heating and

cooling rates; (5) quenching methods; and (6) record and documentation

requirements.

- 43 - Enclosure 2

ii. Nondestructive Examination (NDE)

The inspectors reviewed the manufacturing control plan to ensure the plan

included provisions for monitoring NDE to ascertain that the NDE was performed

in accordance with applicable code, material specification, and contract

requirements.

iii. Welding

The inspectors reviewed the documentation for the weld overlay welding

operations that established a layer of stainless steel cladding on the inside of the

reactor vessel head to determine if it was accomplished per design. The

inspectors also selected a sample of dome-to-flange and control rod drive

mechanism flange-to-nozzle welds and reviewed the following items: (1) certified

mill test reports of the dome, flange, weld material rods, and control rod drive

mechanism nozzles; (2) certified mill test reports for the welding material for the

reactor vessel head cladding; (3) cladding weld records, weld rod material control

requisitions, traceability of weld material rods, weld procedure qualification,

welder qualifications, and nonconformance reports; (4) control rod drive

mechanism nozzle cladding welding inspection records, weld rod material control

requisitions, traceability of weld material rods, weld procedure qualification,

welder qualifications, and nonconformance reports; (5) control rod drive

mechanism to nozzle welding and welds inspection records, weld rod material

control requisitions, traceability of weld material rods, weld procedure

qualification, welder qualifications, and non-conformance reports; and (6) NDE

procedures, NDE records of the welds, NDE personnel qualifications, and

certification of the NDE solvents.

iv. Procedures

Inspections were completed to ensure that repair procedures had been

established and that these procedures were consistent with applicable ASME

Code, material specification, and contract requirements by verifying: (1) repair

welding was conducted in accordance with procedures qualified to Section IX of

the ASME Code; (2) all welders had been qualified in accordance with Section IX

of the ASME Code; (3) records of the repair were maintained; and (4) that

requirements had been established for the preparation of certified material test

reports and that the records of all required examinations and tests were traceable

to the procedures to which they were performed.

v. Code Reconciliation

The inspectors reviewed the required documentation, supplemental

examinations, analysis, and ASME Code documentation reconciliation to ensure

that the original ASME Code N-Stamp remains valid, and that the replacement

head complies with appropriate NRC rules and industry requirements. The

inspectors also ensured that the design specification was reconciled and a

design report was prepared for the reconciliation of the replacement head,

verifying that they were certified by professional engineers competent in ASME

Code requirements.

- 44 - Enclosure 2

vi. Quality Assurance Program

The inspectors verified that: (1) machining was carried out under a controlled

system of operation; (2) a drawing/document control system was in use in the

manufacturing process; and (3) that part identification and traceability was

maintained throughout processing and was consistent with the manufacturer=s

quality assurance program. In addition, the inspectors ensured that only the

specified drawing and document revisions were available on the shop floor and

were being used for fabrication, machining, and inspection.

vii. Compliance Inspection

The inspectors verified that the original ASME Code,Section III, data packages

for the replacement reactor vessel head were supplemented by documents

included in the ASME Code,Section XI, (preservice inspection) data packages;

examined selected manufacturing and inspection records of the finished

machined reactor vessel head; and verified compliance with applicable

documentation requirements.

b. Findings

No findings of significance were identified.

.3.3 Reactor Vessel Head Removal and Replacement Inspections

a. Inspection Scope

The inspectors used the guidance in Inspection Procedure 71007 to perform the

following reactor vessel head removal and replacement inspection activities:

i. Lifting and Rigging

The inspectors reviewed preparations and procedures for rigging and heavy

lifting including crane and rigging inspections, testing, equipment modifications,

laydown area preparations, and training for the following activities:

• Area preparation for the outside systems

• Lattice boom crawler crane assembly, disassembly, and operation

• Hydraulic gantry lift system

• Outside bridge and trolley transfer system

• Elevated cantilevered handling device installation and use

• Reactor vessel head lift rig and polar crane

• Down-ender/up-ender fixture

• Old reactor vessel head removal

• New reactor vessel head placement

• Transport of old reactor vessel head to storage location

ii. Major Structural Modifications

- 45 - Enclosure 2

The inspectors observed that there were no major structural modifications that

were made to facilitate reactor vessel head replacement.

iii. Containment Access and Integrity

The inspectors observed there were no modifications to the existing containment

access structure or integrity to allow for the reactor vessel head to be removed

and installed. The new and old reactor vessel head were moved in and out of

containment using the existing equipment hatch.

iv. Outage Operating Conditions

The inspectors reviewed and observed the establishment of operating conditions

including: (1) defueling; (2) reactor coolant system draindown; (3) system

isolation; (4) safety tagging; (5) radiation protection controls; (6) controls for

excluding foreign materials in the reactor vessel; (7) verification of the suitability

of reinstalled (reused) components for use; and (8) the installation, use, and

removal of temporary services. Section 1R20 of this report documents additional

activities that were performed during the outage.

v. Storage of Removed Reactor Vessel Head

The inspectors reviewed the radiological safety plans and observed the transport,

storage, and radiological surveys of the old reactor vessel head to its onsite

storage location. This review was performed as part of the baseline inspections

conducted during the 2R15 outage and additional information is documented in

Section 2OS2 of this report.

b. Findings

No findings of significance were identified.

.3.4 Post-installation Verification and Testing Inspections

a. Inspection Scope

The inspectors used the guidance in Inspection Procedure 71007 to perform the

following post-installation verification and testing inspection activities. Selective

inspections were performed of the following areas: (1) containment testing;

(2) licensee=s post-installation inspections and verifications program and its

implementation; (3) reactor coolant system leakage testing and review of test results;

(4) procedures required for equipment performance testing to confirm the design and to

establish baseline measurements; and (5) preservice inspection of new welds.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

- 46 - Enclosure 2

On October 20, 2009, the inspectors presented the results of the Unit 2 Inservice

Inspection to Mr. J. Hesser, Vice President Nuclear Engineering, and other members of

the licensee staff. The licensee acknowledged the issues presented. The inspectors

acknowledged review of proprietary material during the inspection which had been or will

be returned to the licensee.

On October 23, 2009, the inspectors presented the results of the Access Control and

ALARA planning inspection to Mr. R. Bement, Vice President, Nuclear Operations, and

other members of his staff who acknowledged the findings. In addition, on

November 8, 2009 the inspectors conducted a telephonic final exit with Mr. D. Mims,

Vice President, Regulatory Affairs and Plant Improvement and other members of staff.

The inspectors confirmed that proprietary information was not provided or examined

during the inspection.

On January 6, 2010, the inspector discussed the inspection results of the licensed

operator requalification program annual operating test with Mr. C. Brown, Licensed

Operator Continuing Training Section Leader. The licensee acknowledged the results.

The inspector confirmed that proprietary information was not provided or examined

during the inspection.

On January 26, 2010, the inspectors conducted an exit to present the inspection results

to Mr. Dwight Mims, Vice President, Regulatory Affairs, and other members of the

licensee's management staff. The licensee acknowledged the issues presented. The

inspectors noted that while proprietary information was reviewed, none would be

included in this report.

On February 3, 2010, the inspectors discussed a change to the inspection results, with

Mr. Ron Barnes, Director of Regulatory Affairs, as presented in January 26, 2010. This

change was to remove one proposed NCV. The licensee acknowledged the updated

information.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the

licensee and is a violation of NRC requirements that meets the criteria of the NRC

Enforcement Policy, to be dispositioned as a noncited violation.

• On December 30, 2009, at 12:03 p.m., Palo Verde Nuclear Generation Station

declared a Notice of Unusual Event for emergency action level HU1, Natural

phenomena affecting the protected area. Following declaration of the Notice of

Unusual Event, the licensee failed to make notifications to State and local

governmental agencies within 15 minutes as required by 10 CFR 50.47(b)(5) and

10 CFR Part 50, Appendix E. This event has been documented in the licensees

corrective action program as PVAR 3421043. The finding is of very low safety

significance because the Emergency Action Level classification did not exceed a

Notice of Unusual Event.

ATTACHMENT: SUPPLEMENTAL INFORMATION

- 47 - Enclosure 2

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

G. Andrews, Unit 3 Assistant Plant Manager

S. Bauer, Director, Regulatory Affairs

J. Bayless, Department Leader, Engineering Programs

R. Barnes, Director, Regulatory Affairs

R. Bement, Vice President, Nuclear Operations

C. Bonhof; Section Leader, Radiation Protection Technical Services

P. Borchert, Unit 1 Assistant Plant Manager

F. Burdick, Regulatory Affairs

R. Buzard, Section Leader, Compliance

J. Cadogan, Director, Engineering Programs

D. Carnes, Unit 2 Assistant Plant Manager

K. Chavet, Senior Consultant, Regulatory Affairs

L. Cortopossi, Plant Manager, Nuclear Operations

D. Coxon, Unit Department Leader, Operations

T. Dickinson; Senior Technical Advisor, Radiation Protection

E. Dutton, Acting Director of Nuclear Assurance

E. Fernandez, Engineer, Engineering Programs

R. Folley, Engineer, Engineering Programs

J. Gaffney, Director, Radiation Protection

T. Gray, Department Leader, Radiological Support Services

B. Haley, Section Leader, Inservice Inspection/Engineering Programs

D. Hautala, Senior Engineer, Regulatory Affairs

J. Hesser, Vice President, Engineering

G. Hettel, Director, Operations

M. Lacal, Director, Performance Improvement

J. McDonnell, Department Leader, Radiation Protection Operations

D. Mims, Vice President, Regulatory Affairs and Performance Improvement

C. Podgurski, Section Leader, Dosimetry, Radiation Protection

F. Poteet, Senior Engineer, Inservice Inspection Program

T. Radtke, General Manager, Emergency Services and Support

M. Ray, Director, Emergency Planning Programs

H. Ridenour, Director, Maintenance

S. Sawtschenko, Department Leader, Emergency Preparedness

D. Steinsiek, Department Leader, Programs Engineering

J. Summy, Director, Plant Engineering

J. Taylor, Unit Department Leader, Operations

T. Weber, Section Leader, Regulatory Affairs

M. Winsor, Director, Strategic Projects

Nuclear Regulatory Commission

M. Runyan, Senior Reactor Analyst, Region IV

A-1 Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000528;529;530/2009005-01 NOV Failure to Establish Adequate Procedures to Control

Potential Tornado Borne Missile Hazards Near the

Essential Spray Ponds (Section 1R15)

Opened and Closed

05000529/2009005-02 NCV Failure to Maintain Containment Closure Capability

(Section 1R20)05000529/2009005-03 NCV Failure to Comply with High Radiation Area Entry

Requirements (Section 2OS1)

05000528;529;530/2009005-04 NCV Failure to Periodically Update the UFSAR (Section

2OS2)

05000528;529;530/2009005-05 NCV Inadequate Procedures to Diagnose and Mitigate a

Loss of Instrument Air to the Containment

(Section 4OA3)

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 1R04: Equipment Alignment

PROCEDURES

NUMBER TITLE REVISION

40ST-9SI13 LPSI and CS System Alignment Verification 18

40OP-9SI01 Shutdown Cooling Initiation 44

33MT-9EC01 Essential Chiller 10

40OP-9EW02 Essential Cooling Water System 13

40OP-9EC02 Essential Chilled Water Train B (EC) 15

40ST-9SI13 LPSI and CS System Alignment Verification 18

A-2 Attachment

DRAWINGS

NUMBER TITLE REVISION

01-M-SIP-001 P and I Diagram Safety Injection and Shutdown Cooling System 44

01-M-SIP-002 P and I Diagram Safety Injection and Shutdown Cooling System 34

01-M-ECP-001 P and I Diagram Essential Chilled Water System 31

1R05: Fire Protection

PROCEDURES

NUMBER TITLE REVISION

14DP-0FP02 Fire System Impairments and Notifications 14

14AC-OFP05 Pre-Fire Strategies Manual Control 21

MISCELLANEOUS

Updated Final Safety Analysis Report, Section 9.5, Revision 11

Pre-Fire Strategies Manual for Condensate Storage Pump House and Tunnel, Revision 21

Pre-Fire Strategies Manual for Auxiliary Building, Revision 21

Section 1R06: Flood Protection Measures

PROCEDURES

NUMBER TITLE REVISION

40OP-9OP26 Operability Determination and Functional Assessment 2

01PR-OAP04 Corrective Action Program 0

01DP-9ZZ01 Systematic Troubleshooting 6

DRAWINGS

NUMBER TITLE REVISION

13-E-ZVU-006 Underground Electrical Duct Layout Plot Plan 33

PALO VERDE ACTION REQUESTS

3397388 3407186 3407186 3344319 3388896 3395895

CONDITION REPORTS / DISPOSITION REPORTS

3411861

WORK ORDERS

3418207 3389954 3398438 3398440 3397408

A-3 Attachment

Section 1R08: In-service Inspection Activities

PROCEDURES

NUMBER TITLE REVISION

73TI-0EE01 Ultrasonic Instrument Calibration 3

73TI-9RC01 Steam Generator Eddy Current Examinations 28

73TI-9ZZ05 Dry Magnetic Particle Examination 14

73TI-9ZZ07 Liquid Penetrant Examination 14

73TI-9ZZ08 High Temperature Liquid Penetrant Examination 13

73TI-9ZZ09 Ultrasonic Examination of Pipe and Vessel Welds 14

73TI-9ZZ10 Ultrasonic Examination of Welds in Ferritic Components 12

73TI-9ZZ79 ASME Section XI Appendix VIII Ultrasonic Examination of Ferritic 6

Piping

73TI-9ZZ80 ASME Section XI Appendix VIII Ultrasonic Examination of 6

Austenitic Piping

73DP-9WP01 Welder and Procedure Qualification 5

73DP-9WP04 Welding and Brazing Control 13

73DP-9WP05 Weld Filler Material Control 6

73DP-9ZZ17 Repair and Replacement - ASME Section XI 19

73DP-9ZC01 Boric Acid Corrosion Control Program 3

70TI-9ZC01 Boric Acid Walkdown Leak Detection 9

73WP-0ZZ07 Welding of Stainless and Nickel Alloys 14

NON-DESTRUCTIVE EXAMINATION REPORTS

09-UT-2075 09-UT-2076 09-PT-2010 09-PT-2011 09-UT-2055 09-UT-2083

09-UT-2076 09-UT-2077 09-UT-2078 09-MT-2050 09-MT-2051 09-UT-2084

09-MT-2052 09-MT-2053 09-PT-579 09-UT-2081 09-UT-2082

CONDITION REPORTS / DISPOSITION REPORTS

3282780 3153607 3297425 3163600 3172539 3395895

3221458 3300934 3329999

A-4 Attachment

WORK ORDERS

3362862

MISCELLANEOUS

NUMBER TITLE REVISION / DATE

107067-006 A and B Train 24 Pipe Spool Repair (Sump October 14, 2009

Isolation Valve) Weld Package

Replacement Steam Generators - Analysts 9

Guidelines Training Manual

3191067 Work order for 2PCHAV328 -Seal Weld Body to October 15, 2009

Bonnet

Unit 2 Inservice Inspection Report Fourteenth June 26, 2009

Refueling Outage

3139194 Inservice Inspection (ISI) Self Assessment, September 18, 2008

3194996 NEI 03-08 Material Initiative Program Self September 24, 2008

Assessment

3327153 Welding Program Self Assessment Report July 17, 2009

2968935 Boric Acid Corrosion Control Program Self- November 16, 2007

Assessment Report,

SG-SGMP-09-12, U2R15 Steam Generator September 25, 2009

Degradation Assessment

Unit 2 Replacement Steam Generators Condition May 9, 2008

Monitoring Report

02-MS-B084, Steam Generator Operational September 26, 2008

Assessment

3139187 Steam Generator Management Program Self March 27, 2009

Assessment Report

102-06061-DEM/RJR , PVNGS Unit 2 Docket September 10, 2009

No. STN 50-529 Request for Relief from ASME

Code Section XI - Relief Request No. 45

Section 1R11: Licensed Operator Requalification Program

PALO VERDE ACTION REQUESTS

3413301 3413305 3413452 3413456

A-5 Attachment

MISCELLANEOUS

Simulator Scenario, SES-0-09-M-03, Generator Trip / ESD / LOAF

Simulator Scenario, SES-0-07-H-02, Slipped CEA / LOFC

Simulator Evaluation Summary Sheet, 12/10/09

Form EP-0541, Palo Verde NAN Emergency Message Form, 12/09/09

Palo Verde Nuclear Training Department Remediation Form

Simulator Performance Indicator Evaluation Form, Revision 4

Section 1R12: Maintenance Effectiveness

PROCEDURES

NUMBER TITLE REVISION

01DP-0ZZ01 Operational Decision Making 2

01PR-OAP04 Corrective Action Program 0

40OP-9MB01 Main Generation and Excitation 46

01DP-9ZZ01 Systematic Troubleshooting 6

70DP-0MR01 Maintenance Rule 8

PALO VERDE ACTION REQUESTS

3387675 3394266 3398587

CONDITION REPORTS / DISPOSITION REPORTS

3394672

WORK ORDERS

3394270

MISCELLANEOUS

System Health Report, MB- Excitation and Voltage Regulation, June 30, 2009

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

PROCEDURES

NUMBER TITLE REVISION

36MT-9SE11 Excore Control Channel Calibration 28

36ST-9SE13 Excore Startup Channel and Boron Dilution Alarm System 28

Calibration

70DP-0RA01 Shutdown Risk Assessments 32

A-6 Attachment

40OP-9ZZ23 Outage GOP 56

32MT-9ZZ82 Time Delay Relay Test 17

40ST-9DG01 Diesel Generator A Test 38

70DP-0RA05 Assessment and Management of Risk When performing 14

Maintenance in Modes 1 and 2

PALO VERDE ACTION REQUESTS

3394870 3403001

CONDITON REPORTS / DISPOSITION REPORTS

3403654 3322007 3353708

WORK ORDERS

3394915 3372009 3386576 3334744 3342189 32621546

3066204 3320938

MISCELLANEOUS

TITLE REVISION / DATE

Operators Risk Report for Unit 1 October 22 - 23, 2009

Operators Risk Report for Unit 2 October 7 - 11, 2009

Control Room Alarm Printout October 22, 2009

Alarm Response Procedure 40AL-9RK4A, Startup and Control 32

Channel Trouble

Alarm Response Procedure 40AL-9RK4A, Automatic Motion Inhibit 32

Troubleshooting Game Plan, Three Spurious Spikes Occurred on October 26, 2009

Unit 3 Excore Control Channel 1

Schedulers Evaluation for Unit 1 September 14 - 21, 2009

Schedulers Evaluation for Unit 1 October 19 25, 2009

Schedulers Evaluation for Unit 2 December 7 - 11, 2009

Shutdown Safety Function Assessment Status Sheet November 9, 2009

A-7 Attachment

Section 1R15: Operability Evaluations

PROCEDURES

NUMBER TITLE REVISION

40DP-9OP26 Operability Determination and Functional Assessment 26

74DP-9CY04 Systems Chemistry Specifications 64

40OP-9CH01 CVCS Normal Operations 58

81DP-0ZY01 Monitoring Outside Areas For Potential Tornado Borne Missile 4

Hazards

DRAWINGS

Number Title Revision

AO-E-NAB-004 Elementary Diagram 13.8KV Non-Class 1E Power System Start- 8

Up XFMR A-E-NAN-X01 Tripping

AO-E-NAB-004 Elementary Diagram 13.8KV Non-Class 1E Power System Start- 10

Up XFMR A-E-NAN-X01 AC Schematic

13-M018-00586 Air Inlet Manifold - Emergency Diesel Generator 6

02-M-CHP-002 P and I Diagram Chemical and Volume Control System, Sheet 1 42

PALO VERDE ACTION REQUESTS

3384205 3039770 3395560 3393504 3319258 338904

3399618 339877 3311997 3393377 3389475 3389652

3390604 3398582 3395707 3393776 3361413 3392783

3419429

CONDITON REPORTS / DISPOSITION REPORTS

3384751

CONDITION REPORT ACTION ITEMS

3392797 3393843 3401239 3401241 3392785 3401243

3401246 3401247 2937383

WORK ORDERS

3384231 3039808 3395562 3398459 2645454

A-8 Attachment

ENGINEERING WORK REQUESTS

3381247 3419684

MISCELLANEOUS

NUMBER TITLE REVISION / DATE

TrueGas Sampled Data for AE-NAN-X01 August 30, 2009 through

September 28, 2009

VTD-Q011-00001 Qualitrol Electronic Pressure Monitor Model Revision 24298

1. 930-010-01 CS 35551 Instruction Manual

DBA Final Report Valspar 84-V-200 October 8, 2009

Letter from ORNL to Mobile Chemical Company July 9, 1976

Letter from Bechtel Power Corporation to Arizona November 30, 1984

Nuclear Power Project

Memorandum to PVGNS from Corrosion Control April 10, 2009

Company Consultants and Labs, Inc

Calculation 2005-09080 2

Valspar product data sheet fro 84-V-2 Clear

Memorandum to PVGNS from Enercon April 17, 2009

Specification 13-AM-314, Installation for Surface 5

Coating Systems for Concrete

Bacterial Collection Data for Unit 2 Spray Pond A November 4, 2009

Technical Evaluation - Ultimate Heat Sink Cooler August 27, 2009

and Spray Pond Fouling due to Bacterial Growth,

Specification 13-CN-0389, Installation 0

Specification for Control of Tornado Borne

Missiles in Outside Areas

Calculation 13-NC-SP-0201, Spray Pond 3

Tornado Missile Damage Frequency

Section 1R18: Plant Modifications

PROCEDURES

NUMBER TITLE REVISION

40DP-9OP26 Operations PVAR Processing and Operability Determination / 26

Functional Assessment

A-9 Attachment

NUMBER TITLE REVISION

81DP-0DC17 Temporary Modification Control 25

EPIP -99 EPIP Standard Appendices 28

40EP-9EO10 Standard Appendices 101 60

40EP-9EO09 Functional Recovery 40

PALO VERDE ACTION REQUESTS

3390185 3390257

CONDITON REPORTS / DISPOSITION REPORTS

3391177

ENGINEERING WORK REQUEST

3390267

TEMPORARY MODIFICATIONS

3274294 3257865

WORK ORDERS

3269250 3251020

MISCELLANEOUS

TITLE DATE

Unit 1 TMOD Status Sheet, October 13, 2009

Technical Issues Briefing Sheet October 13, 2009

System Engineer/EFIN Response to PVAR 3390185/EWR3390267 October 13, 2009

Section 1R19: Post-Maintenance Testing

PROCEDURES

NUMBER TITLE REVISION

73ST-9SI03 Leak Test of Safety Injection / Reactor Coolant System Isolation 44

Valves

73ST-9DG02 1E Diesel Generator and Integrated Safeguards Test Train B 20

40OP-9MB01 Main Generation and Excitation 46

A-10 Attachment

NUMBER TITLE REVISION

73ST-9XI20 ADVs- Inservice Test 25

PALO VERDE ACTION REQUESTS

3387675 3394266 3398587 3382963 3395864 3393536

3411273 3410425 3407446 3407475 3418163

CONDITON REPORTS / DISPOSITION REPORTS

3394672 3419262

WORK ORDERS

3394270 3364810 3241399 3393698 3250960 3410468

3205878 3369024 3407858 3407448 3385202

MISCELLANEOUS

TITLE DATE

Permit # 167123, Troubleshoot loss of blue light indication September 23, 2009

Prompt Human Performance Evaluation Form September 22, 2009

Personal Statements of Events from Operations Personnel September 23, 2009

Red Communication for Site Clock Reset September 24, 2009

Integrated Safeguards Test October 28, 2009

Section 1R20: Refueling and Other Outage Activities

PROCEDURES

NUMBER TITLE REVISION

31MT-9RC30 Reactor Vessel Head Removal and Installation 40

31MT-9RC30 Reactor Vessel Head Removal and Installation 41

40OP-9EO01 Standard Post Trip Actions 16

01DP-9ZZ01 Systematic Troubleshooting 6

40OP-9ZZ23 Outage GOP 56

40OP-9ZZ05 Power Operations 131

40ST-9RC01 RCS and Pressurizer Heatup and Cooldown Rates 15

40OP-9SG01 Main Steam 60

40DP-9OP26 Operability Determination and Functionality Assessment 27

A-11 Attachment

NUMBER TITLE REVISION

40OP-9FT02 Feedwater Pump Turbine B 32

30DP-9WP02 Maintenance Work Order Process and Control 55

40OP-9CH01 CVCS Normal Operations 58

72ST-9RX14 Shutdown Margin, Modes 3, 4, and 5 15

72PY-9RX04 Low Power Physics Tests Using RMAS 16

40DP-9WP01 Operations Processing of Work Orders 15

40DP-9OP29 Power Block Permit and Tagging 35

02DP-0ZZ02 PVNGS Site Tagging Standard 6

51DP-9OM03 Site Scheduling 23

93DP-0LC05 Regulatory Interaction and Correspondence Control 14

40DP-9OP02 Conduct of Shift Operations 49

70DP-0RA03 Probabilistic Risk Assessment Model Control 6

71DP-0EM01 Risk Management Program Expert Panel 9

70DP-0RA05 Assessment and Management of Risk When Performing 13

Maintenance in Modes 1 and 2

40OP-9ZZ04 Plant Startup Mode 2 to Mode 1 56

70DP-0RA01 Shutdown Risk Assessments 32

40OP-9ZZ11 Mode Change Checklist 80

70TI-9ZC01 Boric Acid Walkdown Leak Detection 9

PALO VERDE ACTION REQUESTS

3411749 3411819 3412268 3412244 3412243 3412222

3412110 3412021 3411338 3411374 3411138 3411229

3411137 3386786 3386784 3388733 3388309 3388652

3388536 3388573 3403493 3403408 3401421 3386683

3389625 3390332 3386684 3386683 3400561 3390317

3389284

CRDRs

A-12 Attachment

3404363 3404374 3390784

CRAIs

3404375

WORK ORDERS

9401914 3401915

TAGGING PERMITS

165952 165843 165845 168253 167699 166016

167833 166015 166007 165607

MISCELLANEOUS

NUMBER TITLE REVISION / DATE

2R15 Refueling Outage Probability

Risk Assessment

2R15 Refueling Outage Maintenance

Overview Schedule

Control Room Logs October 2, 2009

Control Room Logs October 3, 2009

Technical Specification 5.5.16 Containment Leakage Rate Testing

Program

Technical Specification 3.6.1 Containment

Technical Specification 3.6.3 Containment Isolation Valves

Technical Specification 3.9.3 Containment Penetrations

Fuel Handling Event Recovery November 13, 2009

Checklist

Personnel Statements from fuel November 13, 2009

moving crew

Technical Issues Briefing Sheet November 7, 2009

Refueling Pool Clarity Iron and Copper

Regulatory Guide 1.163, Performance-

Based Containment Leak-Test

Program

A-13 Attachment

MISCELLANEOUS

NUMBER TITLE REVISION / DATE

Boric Acid Walkdown Inspection , October 3, 2009

Summary and Results

IP 71111.20" NRC Operating Experience Smart

Sample (OpESS) FY 2007-03, "Crane

and heavy lift inspection, supplement

guidance

Technical Specification Component May, 19, 2009

Condition Report

Night Order October 9, 2009

Control room Logs October 8, 2009 through

October 9, 2009

UFSAR Section 3.8 11

UFSAR Section 6.2.1 11

Section 1R22: Surveillance Testing

PROCEDURES

NUMBER TITLE REVISION

73ST-9SP02 Essential Spray Pond Pumps - Comprehensive Pump Test 3

72PY-9RX04 Low Power Physics Tests 18

01PR-0AP04 Corrective Action Program 0

90DP-0IP10 Condition Reporting 18

73ST-0XI04-1 SI Train B Valves-Inservice Test 25

WORK ORDERS

3387348 3250713

Section 2OS1: Access Controls to Radiologically Significant Areas

PROCEDURES

NUMBER TITLE REVISION

75DP-0RP01 Radiation Protection Program Overview 8

75DP-0RP02 Radiation Contamination Control 15

A-14 Attachment

NUMBER TITLE REVISION

75DP-9RP01 Radiation Exposure and Access Control 16

75RP-0RP01 Radiological Posting and Labeling 28

75RP-9RP01 Radiation Exposure and Access Control 15

75RP-9RP07 Radiological Surveys and Air Sampling 19

75RP-9RP10 Conduct of Radiation Protection Operations 30

75RP-9OP02 Control of High Radiation Areas, Locked High Radiation Areas 24

and Very High Radiation Areas

WORK ORDERS

3387348 3250713

PALO VERDE ACTION REQUESTS

3393861 3393937 3394165 3395113 3397279

CONDITION REPORTS / DISPOSITION REPORTS

3311917 3313137 3315758 3315854 3317030 3337883

3328940 3329007 3329010 3329791 3329969 3354528

3393042 3395711 3360300 3379555 3383924 3394172

3384503 3384503 3394172 3395711 3393042

RADIATION EXPOSURE PERMITS, IN-PROGRESS REVIEWS, POST-JOB REVIEWS

NUMBER TITLE

2-1265 Remove/Replace CEA Extension

2-1365 Reactor Drain Tank Repair and Replacement

2-1403 Reactor Coolant Pump Diffuser and Suction Pipe Inspections

2-1424 3-Dimensional Laser Scanning/Templating

2-3000 Control Element Assembly Replacement

2-3002 Reactor Destack and Restack

2-3006 Reactor Vessel Head Penetration Inspection

2-3306 Primary Side Steam Generator Maintenance

2-3320 Remove and Replace Reactor Coolant Pump 1A Impeller and Seal Assembly

2-3412 Pressurizer Heater Cut Out and Replacement

Section 2OS2: ALARA Planning and Controls

PROCEDURES

NUMBER TITLE REVISION

75DP-0RP03 ALARA Program Overview 4

75DP-0RP06 ALARA Committee 5

A-15 Attachment

NUMBER TITLE REVISION

75RP-9RP12 ALARA Reports 3

75RP-9RP15 Control and Storage of Radioactive Material and Radioactive 21

Waste

RADIATION EXPOSURE PERMITS, IN-PROGRESS REVIEWS, POST-JOB REVIEWS

NUMBER TITLE

3-1422 Perform Reactor Coolant System Nozzle Weld Overlays

3-3000 Control Element Assembly Replacement

3-3002 Reactor Destack and Restack

3-3045 Reactor Vessel Head Penetration Inspection

3-3306 Primary Side Steam Generator Maintenance

MISCELLANEOUS

Unit 3 Refueling Outage 14 ALARA Summary Report

S-02-0097, 10 CFR 50.59 for Old Steam Generator Storage Building

S-02-0424, 10 CFR 50.59 for Unit-2 Old Steam Generators

S-08-0372, 10 CFR 50.59 for Old Reactor Vessel Head Building

S-09-0254, 10 CFR 50.59 for Old Reactor Vessel Head, Radiological

Decommissioning Review, September 2009

Old Steam Generator Drop Dose Analysis

Old Reactor Vessel Head Drop Dose Analysis

PV Reactor Vessel Head Characterization Survey Protocol

Section 4OA1: Performance Indicator Verification

PROCEDURES

NUMBER TITLE REVISION

70DP-0PI01 Performance Index Data Mitigating System Cornerstone 4

75RP-0LC01 Performance Indicator Occupational Radiation Safety 2

Cornerstone

75RP-0LC02 Performance Indicator Public Radiation Safety Cornerstone 1

MISCELLANEOUS

Interviews with personnel on November, 20, 2009

Control room logs from September 2009 through November 2009

Unavailability report data from September 2008 through September 2009

Section 4OA2: Identification and Resolution of Problems

PROCEDURES

NUMBER TITLE REVISION

A-16 Attachment

01DP-0AC06 Site Integrated Business Plan/Site Integrated Improvement Plan 11

Process

01DP-0AP12 Palo Verde Action Request Processing 13

01PR-0AP04 Corrective Action Program 4

81DP-0DC13 Deficiency Work Order 26

01DP-0AP16 PVNGS Self-Assessment and Benchmarking 6

60DP-0QQ02 Trend Analysis and Coding 22

PALO VERDE ACTION REQUESTS

3397224 3418201 3418174 3418452 3418441 3418431

3418422 3418404 3418353 3418163 3417573 3417248

3036970 3416748 3416563 3407053

CONDITION REPORTS / DISPOSITON REPORTS

3325283 3038288 3404325 3298555 3301283 3308290

3335049 3365692 3392342 3332710 3408018

CONDITION REPORTS ACTION ITEMS

3404326

WORK ORDERS

3093249 3303043

MISCELLANEOUS

TITLE DATE

System Health Report, GT-Gas Turbine Generators (Station January 1, 2009

Blackout Generators)

through June 30, 2009

PVNGS System Health Report Executive Summary January 1, 2009

through June 30, 2009

Condition Reporting Trend Report 3rd Quarter 2009 December 2, 2009

Condition Reporting Trend Report 2nd Quarter 2009 September 2, 2009

Palo Verde Nuclear Generating Station Monthly Trend Report November 2009

Operations / Refueling Outage Audit Report 2009-010

A-17 Attachment

MISCELLANEOUS

TITLE DATE

Unit 2 Control Room Log July 11, 2007

Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion

PROCEDURES

NUMBER TITLE REVISION

01DP-9ZZ01 Systematic Troubleshooting 6

40AO-9ZZ06 Loss of Instrument Air 30

40DP-9OP26 Operability Determination and Functionality Assessment 27

43AL-3RK1A Window 1A04A, 125V IE CC M41 CHGR A/AC PNL D21 TRBL 39

40AO-9ZZ02 Excessive Reactor Coolant System Leakrate 13

40AL-9RK3A Window 3A10A, LD SYS TRBL 24

40AO-9ZZ05 Loss of Letdown 18

40AO-9ZZ05 Loss of Letdown 19

40AL-9RK3A Window 3A11A, RCP SEAL SYS TRBL 24

40EP-9EO07 Loss of Offsite Power/Loss of Forced Circulation 22

40AL-9RK3A Window 3A12B, RCP CONT BLEED-OFF PRESS HI-HI 24

40AO-9ZZ04 Reactor Coolant Pump Emergencies 21

40AL-9RK4A Window 4A02A, RCP 1A TRBL 32

90DP-0IP06 Reactor Trip Investigation 16

40AL-9RK3A Window 3A08A, CHG HDR SYS TRBL 24

40AL-9RK3A Window 3A07A, REAC DRN LOOP TRBL 24

40AL-9RK3A Window 3A07B, REAC DRN TK PRESS HI 24

AC-0753 Plant Review Board 0

79IS-9SM01 Analysis of Seismic Event 21

40A)-9ZZ21 Acts of Nature 26

PALO VERDE ACTION REQUESTS

3411749 3411819 3412268 3412244 3412243 3412222

3412110 3412021 3411338 3411374 3411138 3411229

3411137

MISCELLANEOUS

TITLE REVISION / DATE

3M15 Maintenance Outage Probability Risk Assessment

3M15 Maintenance Outage Maintenance Overview Schedule

Technical Specification 3.6.1, Containment

Technical Specification 3.6.3, Containment Isolation Valves

A-18 Attachment

MISCELLANEOUS

TITLE REVISION / DATE

Technical Specification 3.9.3, Containment Penetrations

Technical Specification 3.4.14, Reactor Coolant System Operational

Leakage

Unit 3 Plant Performance, Safety Function, and PPS Response December 3, 2009

Evaluation

Post Trip Turbine Building Walkdown Evaluation December 3, 2009

Safety Assessment of Unit 3 Manual Reactor Trip December 3, 2009

Control Systems Response Evaluation for the Unit 3 Manual Reactor December 3, 2009

Trip

Plant Transient Review Assessment for the Unit 3 Manual Reactor Trip December 3, 2009

Generic Letter 88-14, Instrument Air Supply System Problems

Affecting Safety-Related Equipment

PVNGS Emergency Plan

Event History Report, Unit 3 December 3, 2009

Plant Computer Print Out, Unit 3 December 3, 2009

Operator Logs, Unit 3 December 3, 2009

Operator Logs, Unit2 December 30, 2009

Trend Graphs, Unit 3 December 3, 2009

Licensed Operator Continuing Training 2009-2010 Two Year 1

Schedule,

Licensed Operator Continuing Training -Training Program Description 53

A-19 Attachment

Section 4OA5: Other Activities

PROCEDURES

NUMBER TITLE REVISION

MRS-SSP-2349 RRVCH Preps/Installation of Lower SHA Arrangement/Install 1

Dome Insulation (Transco) for Palo Verde Unit 2

MRS-SSP-2350 Remove and Reinstallation of Components from ORVCH to 1

RRVCH

MRS-SSP-2352 Installation of the Replacement Reactor Vessel Closure Head 1

Flange Insulation

MRS-SSP-2490 Fuel Transfer System Control Console Installation 0

PS-PGN-103 General Intermediate and Final Post Weld Heat Treatment 2

Procedure for Replacement Reactor Vessel Closure Head

and Control Element Drive Mechanism

DS-ECT-01 Eddy Current Imaging Procedure for Inspection of RVH 4

Penetrations

DS-UT-01 Ultrasonic Acquisition Procedure for RVH Penetrations 5

PP-NDE-013 NDE Program Plan - Palo Verde Replacement RV Closure 3

Head and CEDM Unit 1,2, and 3

PP-NDE-014 Replacement Reactor Vessel Head PSI Plan - Palo Verde 2

Replacement RV Closure Head and CEDM Unit 1, 2, and 3

PS-N05065V1 Visual and Dimensional Inspection Procedure 0

EPAV1102 Visual (VT-1, VT-3) Examination Procedure for Palo Verde 1, 0

2, and 3 RRVCH

QM-200 Quality Assurance Manual for ASME III and KEPIC-MN and 17

SN Construction and Material Organization Applications

QM-200 Quality Assurance Manual for ASME III and KEPIC-MN and 16

SN Construction and Material Organization Applications

QM-200 Quality Assurance Manual for ASME III and KEPIC-MN and 14

SN Construction and Material Organization Applications

QM-200 Quality Assurance Manual for ASME III and KEPIC-MN and 13

SN Construction and Material Organization Applications

QM-200 Quality Assurance Manual for ASME III and KEPIC-MN and 12

A-20 Attachment

PROCEDURES

NUMBER TITLE REVISION

SN Construction and Material Organization Applications

QM-200S1 Supplement to the Quality Assurance Manual (QM-200) for 0

10 CFR 50 Appendix B, ASME NQA-1 and ANSI N45.2

Applications

PS-PGN-101 General Welding Procedure for Replacement Reactor Vessel 1

Closure Head and Control Element Drive Mechanism

PS-PGN-102 General Repair Welding Procedure for Replacement Reactor 1

Vessel Closure Head and Control Element Drive Mechanism

MRS-SSP-2367 Assembly/Disassembly of ECHD and Assembly/Disassembly 0

of Erection Crane Inside Protected Area

MRS-SSP-2366 Assemble/Disassemble Assembly Crane at RRVCHSR, Up- 1

end RRVCH/Remove Shipping Container and Stage in

RRVCSF, Install SHA and Transport/Stage RRVCH at

Equipment Hatch

MRS-SSP-2349 RRVCH Preps/Installation of Lower SHA Arrangement/Install 1

Dome Insulation (Transco) for Palo Verde Unit 2

31MT-9RC30 Reactor Vessel Head Removal and Installation 41

8302.0002.0000 Operating Instruction for the Multiple Stud Tensioner (MST) 0

MRS-SSP-2360 Installation of Upper Shroud and Lift Rig 1

31MT-9RC01 Reactor Vessel Ventilation, Cable Support Structure and 34

Insulation Removal and Installation

BIGGE 02271-P7 Component Load Test Qualification Procedure 1

BIGGE 02271-P4 Procedure To Remove The Old RVH From The Reactor 2

Containment Building (RCB)

BIGGE 02271-P5 Procedure To Install The New RVH In The Reactor 2

Containment Building (RCB)

BIGGE 02271-P6 Procedure To Move Old RVH To The Old Reactor Vessel 2

Head Storage Facility (ORVHSF)

BIGGE-02271-P3 Procedure To Install And Remove Elevated Cantilever 3

Handling Device (ECHD) And Heavy Lift Crane

BIGGE-02271-P2 Procedure To Install Lower Shroud 2

A-21 Attachment

PROCEDURES

NUMBER TITLE REVISION

BIGGE-02271-P1 Procedure To Upend New RVH 2

30DP-0MP10 Mobile Crane Activities 17

30DP-9MP11 Rigging Field Use 28

30DP-9MP13 Rigging Control 6

30DP-9MP03 FME Control 15

31MT-9ZC07 Miscellaneous Containment Building Heavy Loads 28

DRAWINGS

NUMBER TITLE REVISION

10035E86 Palo Verde Units 1, 2, and 3 SHA Riser Duct and Platform 0

Assembly Installation

BIGGE 06E24-30 Lower Fixed Runway Elevation View RVCH Replacement 2

Project APS-Palo Verde Nuclear Station, Sheets 1

through 8

BIGGE 06E24-4 E.C.H.D. Major Component Erection Plan View RVCH 0

Replacement Project APS-Palo Verde Nuclear Station,

Sheets 1 through 9

BIGGE Job 2271 Install New R.V.C.H. Isometric View 1

DWG 6.0

BIGGE 06E24-41 Elevated Cantilever Handling Device Elevation View 3

Westinghouse Palo Verde Units 1, 2, and 3 Old ACU Lift Rig Removal 0

PVSHA-024 Rigging Plan

Westinghouse Palo Verde Chimney/Damper Removal Rigging Plan A

PVSHA-021

Westinghouse Palo Verde Units 1, 2, and 3 West Missile Shield Duct 0

PVSHA-030 Removal Rigging Plan

Westinghouse Palo Verde Collector Ring Support Structure Removal 0

PVSHA-023 Rigging Plan

Westinghouse Palo Verde 181-0 Platform Beam Removal Rigging Plan 0

PVSHA-027

Westinghouse Palo Verde Units 1, 2, and 3 Tripod Assembly (OLD) 0

PVSHA-014 Rigging Plan

Westinghouse Palo Verde Units 1, 2, and 3 Lift Rig Assembly (OLD) 0

PVSHA-013 Rigging Plan

A-22 Attachment

NUMBER TITLE REVISION

Westinghouse Palo Verde Units 1, 2, and 3 East and West Riser Duct

PVSHA-029 Removal Rigging Plan

Westinghouse 21,500 lb Circular Lifting Rig Assembly 2

10019E32

Westinghouse Palo Verde Units 1, 2, and 3 SHA Lower Shroud 1

10034E05 Assembly

Westinghouse Palo Verde Units 1, 2, and 3 SHA RV Head and Lower 1

100334E04 Shroud Assembly

PALO VERDE ACTION REQUESTS

3397323 3388189 3373828 3377080 3371174 3407979

3405513 3405437 3385220 3390566

VENDOR CORRECTIVE ACTION REPORT (VCAR)

VC-DHI1-08-053 VC-DHI1-08-056 VC-DHI1-08-057 VC-DHI1-08-059

VC-DHI1-08-060 VC-DHI1-08-062 VC-DHI1-08-063 VC-DHI1-08-026

VC-DHI1-08-051 VC-DHI1-08-038 VC-DHI1-08-054 VC-DHI1-08-055

VC-DHI1-08-058 VC-DHI1-08-027 VC-DHI1-07-028 VC-DHI1-07-023

VC-DHI1-07-009 VC-DHI1-07-010 VC-DHI1-07-018 VC-DHI1-07-019

VC-DHI1-09-002

WORK ORDERS

3234508 3234509 3190342 3260625 3233797 3260628

2992340 3095435 3234469 2292760 2992340 3233786

3233804 3270435 3234457 3234460 3234462 3234464

3234466 3234471 3234516 3255281 3256171 3311953

3260610 3234513 3371805 3234413 3377051 3261505

3234456 3234475 3234455 3377053 3266041 3234470

3260621 3255282 3255285 3270435 3234474 3255284

3255281 3234453 3260622 2992340 3095435

WELDING PROCEDURE SPECIFICATIONS

A-A-0308-139 A-A-0308-140 A-A-0308-141 A-F-0308-113 A-T-0308-121

50.59 Screens/Evaluations

E-09-0006 S-08-0372 E-09-0008

A-23 Attachment

CALCULATIONS

TITLE REVISION

PV-111CN-900, Palo Verde RRVCH ASME Section XI Code Reconciliation 2

Methodology

PV-132CN-011, Palo Verde Units 1, 2, and 3 RCEDM ASME Section XI 1

Code Reconciliation Methodology

13-NC-ZY-0295, Reactor Vessel Head Drop Dose Analysis 1

2271-C2.1, Elevated Cantilever Handling Device (ECHD) 0

2271-C7.1, Ground Loading 0

CN-MRCDA-09-51, APS RV Vent Line Repair 0

CN-RIDA-08-25, Palo Verde Units 1, 2, and 3 RVI Evaluation for a Flat, 1

Concentric, Head Drop from 40 Feet

CN-MRCDA-08-49, Palo Verde Units 1, 2, and 3 Reactor Vessel, Supports, 1

and Main Loop Piping Evaluation for a Concentric Head Drop from 40 Feet

MISCELLANEOUS

NUMBER TITLE REVISION / DATE

13-MN-741 Technical Specification for Control Element 1

Drive Mechanisms for Palo Verde Nuclear

Generating Station Units 1, 2, and 3

13-MN-740 Technical Specification for Replacement 1

Reactor Vessel Heads for Palo Verde Nuclear

Generating Station Units 1, 2, and 3

AHTR-RRVCH-01 Accumulated Heat Treatment Time Record May 18, 2009

PWHT-08-050 Heat Treatment Record June 10, 2008

MRS-SSP-2364 Remove and Re-install Equipment Closure

Hatch

MRS-SSP-2351 Packaging, RP Prep For Removal ORVCH

MRS-SSP-2353 Remove and Modify RCS Vent Line

PWHT-07-093 Heat Treatment Record October 15, 2007

A-24 Attachment

MISCELLANEOUS

NUMBER TITLE REVISION / DATE

DS-ME-06-3 Design Specification for the Palo Verde Units 1, 5

2, and 3 Replacement Reactor Vessel Closure

Head (RRVCH)

500297092 Quality Verification Documentation - 0

Replacement Reactor Vessel Closure Head

(RRVCH) and Control Element Drive

Mechanisms,- Volume 1 of 8

500297092 Quality Verification Documentation - 0

Replacement Reactor Vessel Closure Head

(RRVCH) and Control Element Drive

Mechanisms - Volume 2 of 8

DAR-MRCDA-07-8 Palo Verde Nuclear Generating Station Units 1, 3

2, and 3 - RVLMS

PV-111AR-001 Design Report of Palo Verde Units 1, 2, and 3 12

RRVCH

PV-132AR-001 Design Report of Palo Verde Nuclear Power 1

Plant Units 1, 2, and 3 Replacement CEDM

A-DHI1-08-12 PBSA Worksheet - Reactor Vessel Heads, 31

Control Element Drive Mechanisms (CEDMs),

A-DHI1-08-12 Doosan Triennial Audit - Technical December 11, 2008

Specification Observations

A-DHI1-08-12 Nuclear Procurement Issues Committee Audit 13

Checklist

06-001 Quality Assurance Audit Reports, Logs, and 001

Schedules

SV-DHI1-06-020 Oversight of Palo Verde Units 1, 2, and 3 December 18, 2006

Replacement Reactor Vessel Closure

Heads and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-07-004 Oversight of Palo Verde Units 1, 2, and 3 March 15, 2007

Replacement Reactor Vessel Closure Head -

Bar, Nicrofer 6030 (Alloy 690) for RRVCH

Nozzles

A-25 Attachment

MISCELLANEOUS

NUMBER TITLE REVISION / DATE

SV-DHI1-07-005 Oversight of Palo Verde Units 1, 2, and 3 April 11, 2007

Replacement Reactor Vessel Closure

Heads and Control Element Drive Mechanisms

(CEDM

SV-DHI1-07-0 Oversight of Palo Verde Units 1, 2, and 3 April 13, 2007

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-07-009 Oversight of Palo Verde Units 1, 2, and 3 July 12, 2007

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-07-013 Oversight of Palo Verde Units 1, 2, and 3 September 13, 2007

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-07-014 Oversight of Palo Verde Units 1, 2, and 3 September 19, 2007

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-07-019 Oversight of Palo Verde Units 1, 2, and 3 December 5, 2007

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-08-002 Oversight of Palo Verde Units 1, 2, and 3 February 9, 2008

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-08-006 Oversight of Palo Verde Units 1, 2, and 3 April 2, 2008

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

N001-0303-00172, Palo Verde Units 1, 2, and 3 0

RVI Evaluation for a Flat, Concentric, Head

Drop from 40 Feet

N001-0303-00171 Palo Verde Units 1, 2, and 3, Reactor Vessel, 0

Supports, and Main Loop Piping Evaluation for

a Concentric Load Drop from 40 Feet

A-26 Attachment

MISCELLANEOUS

NUMBER TITLE REVISION / DATE

N001-0303-00171 Palo Verde Units 1, 2, and 3, Reactor Vessel, 1

Supports, and Main Loop Piping Evaluation

for a Concentric Load Drop from 40 Feet

Lift Rig Assembly Load Test Record 0

Tripod Assembly Load Test Data For 1,388,000 July 30, 2009

lb Test

Simplified Head Assembly Radwaste Disposal

Plan

02271-G1 Project Execution Plan

Liebler Crawler Crane LR 1300 Operating

Manual

Spill Prevention and Response Plan for Field

Operators

BIGGE Power Constructors, Palo Verde October 15, 2009

Nuclear Station Job 02271 - Training Matrix

SV-DHI1-08-007 Oversight of Palo Verde Units 1, 2, and 3 April 10, 2008

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-08-013 Oversight of Palo Verde Units 1, 2, and 3 July 9, 2008

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-08-017 Oversight of Palo Verde Units 1, 2, and 3 September 19, 2008

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-08-020 Oversight of Palo Verde Units 1, 2, and 3 October 31, 2008

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-08-022 Oversight of Palo Verde Units 1, 2, and 3 December 24, 2008

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

A-27 Attachment

MISCELLANEOUS

NUMBER TITLE REVISION / DATE

SV-DHI1-09-001 Oversight of Palo Verde Units 1, 2, and 3 February 6, 2009

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM

SV-DHI1-09-002 Oversight of Palo Verde Units 1, 2, and 3 March 26, 2009

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-09-004 Oversight of Palo Verde Units 1, 2, and 3 June 2, 2009

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

SV-DHI1-09-005 Oversight of Palo Verde Units 1, 2, and 3 May 28, 2009

Replacement Reactor Vessel Closure Heads

and Control Element Drive Mechanisms

(CEDM)

RVHR/SHA Radwaste Offload Plan

Westinghouse Head Replacement and SHA 1

Upgrade, PVNGS Material Disassembly and

Removal

BIGGE Drawing Transmittal Log 13

500522911-FDR-01 Field Deviation Report September 11, 2009

901108-OP-001 Operational Procedure Vent Line Repair Cold 0

Bending Tool-Palo Verde

09-446 U2 RV Head Vent Line Coupling DM Weld and September 12, 2009

CEDM 89 Liquid Penetrant Examination Report

Engineering Disposition for ENG-DM 3190342

Reactor Vessel Closure Head Haul Route

Head Lift Rig Assembly Load Test Data August 3, 2009

Reactor Vessel Closure Head Haul Route, 0

Design Input Requirements Checklist

A-28 Attachment