IR 05000275/2006003

IR 05000275-06-003, 05000323-06-003; 4/1/06 - 6/30/06; Diablo Canyon Power Plant Units 1 and 2; Inservice Inspection Activities, Operability Evaluations, Refueling and Outage Activities, and Access Control to Radiologically Significant Area

ML062270051
Person / Time
Site:	Diablo Canyon
Issue date:	08/14/2006
From:	William Jones NRC/RGN-IV/DRP/RPB-B
To:	Keenan J Pacific Gas & Electric Co
References
IR-06-003
Download: ML062270051 (59)

Text

August 14, 2006 John Senior Vice President - Generation

and Chief Nuclear Officer

Pacific Gas and Electric Company

P.O. Box 770000

Mail Code B32

San Francisco, CA 94177-0001SUBJECT:DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000275/2006003 AND 05000323/2006003

Dear Mr. Keenan:

On June 30, 2006, the U.S. Nuclear Regulatory Commission completed an inspection at your Diablo Canyon Power Plant, Units 1 and 2, facility. The enclosed integrated report documents

the inspection findings that were discussed on July 12, 2006, with Mr. James Becker and

members of your staff.

This inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your

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

interviewed personnel.

There were four NRC-identified findings and one self-revealing finding of very low safety significance (Green) identified in this report. These findings involved violations of NRC

requirements. However, because of their very low risk significance and because they are

entered into your corrective action program, the NRC is treating these five findings as noncited

violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this

inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional

Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza Drive, Suite

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

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

Canyon Power Plant.

Pacific Gas and Electric Company- 2 -

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document

Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/William B. Jones, Chief Project Branch B

Division of Reactor Projects Dockets: 50-275 50-323

Licenses: DPR-80

DPR-82

Enclosure:

Inspection Report 05000275/2006003

and 05000323/2006003

w/attachment: Supplemental Information

REGION IVDockets:50-275, 50-323 Licenses:DPR-80, DPR-82 Report:05000275/2006003 05000323/2006003Licensee:Pacific Gas and Electric Company (PG&E)

Facility:Diablo Canyon Power Plant, Units 1 and 2 Location:7 1/2 miles NW of Avila Beach Avila Beach, CaliforniaDates:April 1 through June 30, 2006 Inspectors:T. Jackson, Senior Resident Inspector T. McConnell, Resident Inspector

S. Graves, Reactor Inspector

P. Gage, Senior Operations Engineer

R. Lantz, Senior Emergency Preparedness Inspector

J. Tapia, Senior Reactor Inspector

B. Tharakan, Health PhysicistApproved By:W. B. Jones, Chief, Project Branch B Division of Reactor Projects Enclosure-2-

SUMMARY OF FINDINGS

IR 05000275/2006-003, 05000323/2006-003; 4/1/06 - 6/30/06; Diablo Canyon Power Plant

Units 1 and 2; Inservice Inspection Activities, Operability Evaluations, Refueling and Outage

Activities, and Access Control to Radiologically Significant Areas.

This report covered a 13-week period of inspection by resident inspectors and announced inspections in radiation protection, emergency preparedness, operator requalification, and in-

service inspections. One self-revealing and four NRC-identified, Green, noncited violations 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 review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor

Oversight Process," Revision 3, dated July 2000.A.

Cornerstone: Mitigating Systems

Green.

A self-revealing, noncited violation of 10 CFR Part 50, Appendix B,Criterion XVI, was determined for the failure of operations personnel to promptly identify a condition adverse to quality. Specifically, on November 27, 2005, operators failed to document, in the corrective action program, an unexpected level drop in Accumulator 1-3. Failure to enter the occurrence into the corrective action program precluded actions that would have addressed similar conditions that resulted in a subsequent event involving an unexpected level drop and water hammer associated with Accumulator 2-3, which occurred on May 21, 2006.

This issue was entered into Pacific Gas and Electric Company's corrective action program as Action Request A0669468.

The finding is greater than minor because it is associated with the Mitigating Systems Cornerstone attribute of configuration control and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Using the Inspection Manual Chapter 0609, "Significance Determination

Process," Phase 1 Worksheet, the finding is determined to be of very low safety significance because the finding did not represent a loss of a safety function, an actual loss of a safety-related train for greater than its Technical Specification allowed outage time, or screen as potentially risk-significant due to seismic, fire, flooding, or severe weather initiating events. The finding had a crosscutting aspect in the area of problem identification and resolution because operations personnel failed to promptly identify, in the corrective action program, the unexpected level drop in Accumulator 1-3 (Section 1R15).*Green. An NRC-identified, noncited violation of Technical Specification 5.4.1.a for an inadequate procedure, Procedure OP A-2:II, "Reactor Vessel - Draining the RCS to the Vessel Flange - With Fuel in Vessel," Revision 33A. Specifically, on April 20, 2006, while operators depressurized the reactor coolant system, with Enclosure-4-water level 2 feet below the reactor vessel flange, the two required level instruments, wide-range reactor vessel refueling level indication system and

LI-400, read 15 inches higher than actual reactor vessel water level. The inspectors determined that the procedure was not adequate because prior operating experience had not been incorporated into the procedure that demonstrated the level instruments would read nonconservatively during the reactor coolant system depressurization. Also, Procedure OP A-2:II did not have criteria that alerted operators to abnormal level instrument deviations that may be caused by phenomenon outside of the level deviations expected by the reactor coolant system depressurization. Pacific Gas and Electric Company has planned to evaluate potential changes to Procedure OP A-2:II and reactor coolant system water level instrumentation when used during reactor coolant system depressurization. This issue was entered into Pacific Gas and Electric

Company's corrective action program as Action Requests A0664484, A0672419, and A0672422.

The finding is greater than minor because it is associated with the Mitigating Systems Cornerstone attribute of procedure quality and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Using Inspection Manual Chapter 0609, Appendix G, Attachment 1, Checklist 3, the finding is determined to be of very low safety significance since an optional set of instrumentation provided accurate reactor coolant system level indication and there was no loss of reactor coolant system inventory control. The finding had a crosscutting aspect in the area of human performance for resources because Pacific Gas and Electric Company failed to ensure the adequacy of procedures used for reactor vessel level monitoring to ensure nuclear safety (Section 1R20).*Green. An NRC-identified noncited violation of 10 CFR Part 50, Criterion XVI,"Corrective Actions," was determined for the failure to prevent recurrence of a similar failures, that occurred between 2003 and 2006, of Limitorque SMB-000 actuators in the auxiliary feedwater sy stem. Pacific Gas and Electric Company staff failed to adequately troubleshoot and provide for timely corrective actions regarding auxiliary feedwater control valves that failed due to high actuator torque switch resistance. This finding was entered into Pacific Gas and Electric

Company's corrective action program as Nonconformance Report N0002205.

The finding is greater than minor because it is associated with the Mitigating Systems Cornerstone attribute of equipment performance and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Inspection Manual Chapter 0609, "Significance

Determination Process," Phase 1 Worksheet, the finding is determined to be of very low safety significance because it did not represent an actual loss of safety function, represent an actual loss of safety function for a single train for greater than the Technical Specification allowed outage time, or screen as potentially risk significant due to seismic, fire, flooding, or severe weather initiating events. The finding had a crosscutting aspect in the area of problem identification and Enclosure-5-resolution since Pacific Gas and Electric Company staff failed to adequately trend, assess, and troubleshoot previous Limitorque SMB-000 actuator failures (Section 4OA5.3).

Cornerstone: Barrier Integrity

Green.

An NRC-identified noncited violation of Technical Specification 5.4.1 was identified because Pacific Gas and Electric Company failed to follow the procedure for ensuring that welding preheat temperatures were verified prior to welding. Specifically, during the replacement of Component Cooling Water

Valves 279 and 280, which provide cooling to the reactor vessel support pads,

Pacific Gas and Electric Company failed to verify that the minimum welding preheat temperature of 50°F was met, and could not demonstrate that the ambient temperature was greater than 50°F. Pacific Gas and Electric Company surveyed the area and entered the finding into their corrective action program as

Action Request A0665588.

The finding was greater than minor because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and impacted the cornerstone objective of providing reasonable assurance that physical design barriers, in this case the reactor coolant system, protect the public from radio-

nuclide releases caused by accidents or events. The finding was determined to be of very low safety significance based on management review of the plant conditions at the time the performance deficiency occurred (defueled) and the condition was evaluated prior to the plant entering Mode 5 (Section 1R08).

Cornerstone: Occupational Radiation Safety

Green.

The inspectors identified a noncited violation of 10 CFR 20.1501(a)because Pacific Gas and Electric Company failed to survey to determine the extent and magnitude of radiation levels and evaluate the radiological hazards.

Specifically, on April 18, 2006, the inspectors identified elevated radiation levels near two chemical volume control system valves located in a hallway on the 100-foot elevation of Unit 2. Pacific Gas and Electric Company confirmed elevated radiation levels near the valves were as high as 200 millirem per hour on contact and 28 millirem per hour at 30 centimeters. Pacific Gas and Electric

Company surveyed the area and entered the finding into their corrective action program as Action Request 0665039.

The finding was greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Exposure Control and

Monitoring and affected the cornerstone objective to ensure the adequate protection of a worker's health and safety from exposure to radiation because workers could have unknowingly received additional radiation exposure. When going through the Occupational Radiation Safety Significance Determination

Process, the finding was determined to be of very low safety significance because it was not an as low as is reasonably achievable finding. There was no overexposure or substantial potential for an overexposure, and the ability to assess dose was not compromised. The finding also had crosscutting aspects Enclosure-6-associated with human performance because adequate resources were not established for the survey requirements (Section 2OS1).

Enclosure-7-

REPORT DETAILS

Summary of Plant Status

Diablo Canyon Unit 1 operated at 100 percent power for this inspection period.

Diablo Canyon Unit 2 began this inspection period at 100 percent power and entered Refueling Outage 2R13 on April 17, 2006. Unit 2 entered Mode 6 (Refueling) for core offload operations

on April 20, which was completed on April 25. Unit 2 entered Mode 6 on May 11 when

operators began reloading fuel into the core, and then entered Mode 5 (Cold Shutdown) on

May 17 when maintenance personnel tensioned the reactor vessel head. Operators

commenced a heatup of the reactor coolant system (RCS), and Unit 2 entered Mode 4 (Hot

Shutdown) on May 21 and Mode 3 (Hot Standby) on May 23. On May 24, operators proceeded

with reactor startup, entering Mode 2 (Startup). Operators increased reactor power, and Unit 2

entered Mode 1 (Power Operations) on May 25. On May 25, Unit 2 was paralleled to the grid, ending Refueling Outage 2R13. On May 26, the operators removed the unit from the grid due

to a seal rub on the low pressure turbine. The main turbine was subsequently paralleled to the

grid on the same day. Operators continued to raise reactor power and, on June 5, Unit 2

reached 100 percent power. On June 21, Unit 2 reduced power to 82 percent to perform

maintenance on high pressure turbine governor Valve FCV-142. Unit 2 was returned to

100 percent power on the same day and remained at that power level for the remainder of the

inspection period.1.REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R04Equipment Alignments (71111.04)

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors:

(1) walked down portions of the three below listed risk-important systems and reviewed plant procedures and document s to verify that critical portions of the selected systems were correctly aligned; and

(2) compared deficiencies identified

during the walkdown to the Final Safety Analysis Report (FSAR) Update and corrective

action program (CAP) to ensure problems were being identified and corrected.*April 17, 2006: Unit 2, RCS piping*May 5, 2006: Unit 2, Vital Batteries 2-1, 2-2, and 2-3

• June 28, 2006: Unit 1, Safety Injection Pump 1-1 Documents reviewed by the inspectors included:

• Procedure OP B-3A:II, "Safety Injection System Alignment Verification for Plant Startup," Revision 23,*Drawing 106709, "Safety Injection," Sheet 4, Revision 54

-8-The inspectors completed three samples.

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors:

(1) reviewed plant procedures, calculations, the FSAR Update, Technical Specifications (TSs), and vendor manuals to determine the impact of ultra-low

sulfur diesel fuel on the capability of the diesel engine generators;

(2) reviewed

outstanding design issues, operator workarounds, and FSAR Update documents to

determine if open issues affected the functionality of the diesel engine generators; and

(3) verified that Pacific Gas and Electric Company (PG&E) was identifying and resolving

equipment alignment problems. Documents revi ewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

.1 Quarterly Inspection

a. Inspection Scope

The inspectors walked down the six below listed plant areas to assess the material condition of active and passive fire protection features and their operational lineup and

readiness. The inspectors:

(1) verified that transient combustibles and hot work

activities were controlled in accordance with plant procedures;

(2) observed the

condition of fire detection devices to verify they remained functional;

(3) observed fire

suppression systems to verify they re mained functional and that access to manual actuators was unobstructed;

(4) verified that fire extinguishers and hose stations were

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

(5) verified that passive fire protection features (electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems) were in a

satisfactory material condition;

(6) verified that adequate compensatory measures were

established for degraded or inoperable fire protection features and that the

compensatory measures were commensurate with the significance of the deficiency; and

(7) reviewed the FSAR Update to determine if PG&E identified and corrected fire

protection problems.*April 10, 2006: Unit 2, 140 foot turbine building

-9-*April 14, 2006: Unit 2, 64 foot auxiliary building*May 1, 2006: Units 1 and 2, intake structure

• May 2, 2006: Unit 2, Containment Fire Zones 1A, 1B, and 1C

• May 2, 2006: Unit 1, 85 foot auxiliary building

• May 8, 2006: Security diesel engine generator building Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (71111.06)

Annual External Flooding

a. Inspection Scope

The inspectors:

(1) reviewed the FSAR Update, the flooding analysis, and plant procedures to assess seasonal susceptibilities involving external flooding;

(2) reviewed

the FSAR Update and CAP to determine if PG&E identified and corrected flooding

problems;

(3) inspected underground bunkers/manholes to verify the adequacy of:

(a) sump pumps,

(b) level alarm circuits,

(c) cable splices subject to submergence, and

(d) drainage for bunkers/manholes;

(4) verified that operator actions for coping with

flooding can reasonably achieve the desired outcomes; and

(5) walked down the one

below listed area to verify the adequacy of:

(a) equipment seals located below the

floodline,

(b) floor and wall penetration seals,

(c) watertight door seals,

(d) common drain

lines and sumps,

(e) sump pumps, level alarms, and control circuits, and

(f) temporary or

removable flood barriers.*April 2, 2006: Units 1 and 2, 500 kV switchyard Pullboxes W-3 and W-4

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

The inspectors reviewed PG&E's programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for

Component Cooling Water Heat Exchangers 1-1 and 1-2. The inspectors verified that:

-10-(1) performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors;

(2) PG&E utilized the periodic maintenance method

outlined in Electric Power Research Institute NP-7552, "Heat Exchanger Performance

Monitoring Guidelines;"

(3) PG&E properly utilized biofouling controls;

(4) PG&E's heat

exchanger inspections adequately assessed the state of cleanliness of their tubes, and

(5) the heat exchanger was correctly categorized under the Maintenance Rule.

Documents reviewed by the inspectors included Procedure PEP -234, "CCW Heat Exchanger Performance Test," Revision 9.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities (71111.08)

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

Reactor Vessel Upper Head Penetration Inspections, Boric Acid Corrosion Control

a. Inspection Scope

The procedure requires review of two or three types of nondestructive examination (NDE) activities (volumetric, surface, and visual.) The inspector reviewed multiple examples of all three types.

The procedure requires review of one or two ex aminations from the previous outage with recordable indications that were accepted for continued service. The inspector reviewed

one such examination (Residual Heat Removal System Piping Weld RB-119-II).

If PG&E completed welding on the pressure boundary for Class 1 or 2 systems since the beginning of the previous outage, the procedure requires verification for one-to-three

welds that acceptance and preservice examinations were done in accordance with

American Society of Mechanical Engineers (ASME) Code. The inspector verified one

such weld (Safety Injection System Weld 2SI-119-8III).The procedure requires verification that one or two ASME Section XI Code repairs orreplacements meet Code requirements. The inspector verified two Section XI repairs (replacement of Component Cooling Water Valves 2-279 and 2-280 and replacement of

Residual Heat Removal Valve 2-8742B).

The inspector verified, through direct observation or record review, that ultrasonic, eddy current, liquid penetrant, radiographic, or visual examinations of the components listed

below were performed in accordance with ASME Code requirements.

-11-System Component/Weld Identification Examination MethodFeedwaterSteam Generator 1 Feedwater Supply Hanger 2037-7V Visual (VT-3)

Auxiliary Feedwater (AFW)

AFW Pump 2-1 Discharge Header Hanger 414-505R Visual (VT-3)AFWAFW Pump 2-1 Discharge Header Hanger 414-386R Visual (VT-3)AFWAFW Supply Hanger 42-42RVisual (VT-3)

Chemical Volume Control SystemCVCS-2-8388C, FW-2RadiographicFeedwaterK16-555-16/Integral AttachmentsMagnetic Particle &

UltrasonicFeedwaterK16-557-16Magnetic Particle &

UltrasonicReactor CoolantS6-959-2 SPL WIB-503Liquid Penetrant Reactor CoolantS6-959-2 SPL WIB-1009Liquid Penetrant Reactor VesselCircumferential Weld 9-201Ultrasonic Reactor VesselLoop 2 Outlet Safe-endUltrasonic During the review of each examination, the inspector verified that the correct NDE procedures were used, that examinations and conditions were as specified in the

procedure, and that test instrumentation or equipment was properly calibrated and within

the allowable calibration period. The inspector also reviewed documentation such as

ultrasonic and eddy current inspection records to determine if the indications revealed by

the examinations were compared against the ASME Code specified acceptance

standards. This review also determined that indications were appropriately

dispositioned.

The inspector verified the NDE certifications of those personnel observed performing examinations or identified during review of completed examination packages.

The inspector also reviewed the replacement of four valves performed in accordancewith ASME Section XI. During the replacement of two component cooling water valves

-12-that supply cooling to the reactor vessel support pads, the inspector found that PG&E did not verify the minimum preheat temperature prior to welding.

The minimum sample requirements of the inspection procedure were satisfied.

b. Findings

Introduction

A Green, noncited violation (NCV) of TS 5.4.1.a was identified for failure to follow the procedure for ensuring that welding preheat temperatures were verified prior

to welding. Specifically, on April 26, 2006, during the replacement of Component

Cooling Water Valves 279 and 280, which provide cooling to the reactor vessel support

pads, PG&E failed to verify that the minimum welding preheat temperature of 50°F was

met and PG&E could not demonstrate that the ambient temperature was greater than

50°F. Description

The replacement of Valves 279 and 280 was performed in accordance with Work Order CO196956, which referenced Welding Procedure Specification 5, "Welding

of P1 Materials with GTAW and/or SMAW," Revision 8; Nuclear Welding Control Manual

Procedures GWS-ASME,"ASME General Welding Standard," Revision 8; and WI-1, "Visual Inspection of Welds," Revision 7. Welding Procedure Specification 5 lists a

minimum preheat temperature of 50°F as an essential variable. Section 4.5 of

GWS-ASME states that preheat temperature shall be verified with thermocouples or

temperature indicating crayons or contact pyrometers outside the weld joint but near the

weld area. Section 6.7 of Procedure WI-1 states that verification of preheat temperature

is not mandatory for welds that require a minimum preheat of 50°F, if it can be

demonstrated that the ambient temperature is greater than 50°F. During the

replacement of Valves 279 and 280, PG&E did not verify the preheat temperature prior

to welding. The containment building was open to the environment and no ambient

temperature measurement was performed to demonstrate that the ambient temperature was greater than 50°F.

Analysis:

The performance deficiency associated with this finding is a failure to follow procedures. This deficiency impacted the Barrier Integrity Cornerstone and, as

described in Inspection Manual Chapter (IMC) 0612, Appendix B, the finding was

considered more than minor since it affected the cornerstone objective of providing

reasonable assurance that physical design barriers, in this case the RCS, protect the

public from radionuclide releases caused by a ccidents or events. Specifically, the failure to ensure minimum preheat temperature prior to welding affected the cornerstone

attribute of human performance and its impact on maintaining functionality of the RCS

because not adequately controlling the welding process can lead to weld failures.

Minimum preheat temperature is defined in Section IX of the ASME Code as an

essential variable which can affect the mechanical properties of a weldment. For carbon

steels or low alloy steels, the failure to observe the specified minimum preheat

temperature could result in too rapid cooling and the formation of martensite, a brittle

structure. Rapid cooling could also impede the ability of the weldment to evolve gases

introduced or formed during the welding operation, leading to hydrogen embrittlement.

The finding was determined to be of very low safety significance based on management

review of the plant conditions at the time the performance deficiency occurred (defueled)

and the condition was evaluated prior to the plant entering Mode 5.

-13-Enforcement

TS 5.4.1.a requires that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in

Appendix A of Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Appendix A, Section 9, lists procedures for performing maintenance activities, such as

welding. Welding Procedure Specification 5 and Nuclear Welding Control Manual

Procedures GWS-ASME and WI-1 require that minimum preheat temperature be verified

prior to welding. Contrary to the above, on April 24, 2006, PG&E failed to follow these

procedures by not verifying the preheat tem perature nor that the ambient temperature was above 50°F before beginning welding on Component Cooling Water Valves 279

and 280. Because the failure to follow procedures was of very low safety significance

and has been entered into the CAP as Action Request (AR) A0665588, this violation is

being treated as an noncited violation, consistent with Section VI.A of the NRC

Enforcement Policy: NCV 50-323/06-03-01, Failure to Follow Procedures for Welding.

.2 Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

The inspector reviewed PG&E's reactor vessel upper head penetration (VUHP) nozzle inspection activities implemented in accordance with the requirements of NRC

Order EA-03-009, issued on February 20, 2004. PG&E's nonvisual NDE technique was

a surface examination using ultrasonic and eddy current testing of the wetted surface of

the VUHP nozzle base material and the J-groove weld.

The inspector observed a sample of NDE performed on the vessel head from remote video feeds at the collection and analysis stations. The inspector examined ultrasonic

and eddy current data collected. A review of the NDE examination procedures used was

also performed to confirm that they were consistent with the ASME Code and that the

equipment and calibration requirements were consistent with that used in mockup

demonstrations on simulated actual cracking. The inspector also reviewed records

indicating the extent of inspection for each penetration nozzle, including documents

which resolved interference or masking issues. Specifically, the inspector verified that

PG&E achieved ultrasonic testing coverage to the maximum extent possible. In all

cases, the coverage was from 2 inches above the J-groove weld down to the lowest

elevation that could be practically inspected on each nozzle with the ultrasonic testing

probe being used with a minimum required inspection distance of 0.3 inches below the

J-groove weld. This criteria was specified in an NRC approved alternate examination

criteria for 78 VUHP nozzles.

For all activities reviewed, the inspector determined that the activities were performed in accordance with the requirements of the NRC Order. No indications or defects were

detected. There had not been any indications previously identified which had been

accepted for continued service.

The minimum sample requirements of the inspection procedure were satisfied.

b. Findings

No findings of significance were identified.

-14-

.3 Boric Acid Corrosion Control Inspection Activities (Pressurized Water Reactors)

a. Inspection Scope

The inspector reviewed a sample of boric acid corrosion control walkdown visual examination activities. The inspector determined that PG&E's visual inspections

emphasized locations where boric acid leaks could cause degradation of safety

significant components.

The inspector reviewed three engineering evaluations performed for boric acid found on RCS piping and components. The review verified that ASME Code wall thickness

requirements were maintained and that the degraded conditions were properly entered

and dispositioned in PG&E's CAP.

The minimum sample requirements of the inspection procedure were satisfied.

b. Findings

No findings of significance were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The inspector verified that the steam generator tube eddy current examination scope and expansion criteria met the TS requirements, industry guidelines, and commitments

made to the NRC. The inspector confirmed that known areas of potential degradation

based on site-specific and industry experience were included in the scope of the

inspection. The inspector observed the collection and analysis of eddy current data by

contractor personnel and verified that:

(1) the eddy current probes being utilized were

appropriate for identifying the expected types of indications,

(2) probe position location

verification was being performed,

(3) calibration requirements were being adhered to, and

(4) probe travel speed was in accordance with procedural requirements.

The inspector verified that PG&E compared flaws detected during the current outage against the previous outage data and that appropriate repair criteria was specified. One

hundred percent of all steam generator tubes were inspected during this outage. The

inspector noted that the number of tubes required to be plugged was consistent with

predictions made prior to the start of the outage. Tube plugging activities during the

inspection were in accordance with procedural requirements and were within the

allowable limits for tube plugging.

The minimum sample requirements of the inspection procedure were satisfied.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

-15-

.1 Quarterly Inspection

a. Inspection Scope

The inspectors observed testing and training of senior reactor operators and reactor operators to identify deficiencies and discrepancies in the training, to assess operator

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

positive displacement pump overcurrent trip , loss of a vital 4 kV bus, an earthquake, and an anticipated transient without scram.

Documents reviewed by the inspectors included Lesson FRS1-A, Attachment 2,"Simulator Event Sequence," Revision 14.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.2 Biennial Inspection

a. Inspection Scope

Following the completion of the annual operating examination testing cycle, which ended the week of April 4, 2006, the inspectors reviewed the overall pass/fail results of the

annual individual job performance measure operating tests and simulator operating tests

administered by PG&E staff during the operator licensing requalification cycle. Sixteen

separate crews participated in simulator operating tests, and 79 licensed operators took

the job performance measure operating tests. All of the crews tested passed the

simulator portion of the annual operating test. All of the licensed operators, except one, passed the job performance measure portion of the examination. The licensed operator

was successfully remediated prior to returning to shift. These results were compared to

the thresholds established in IMC 609, Appendix I, "Operator Requalification Human

Performance Significance Determination Process." The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors reviewed the one below listed maintenance activity to:

(1) verify the appropriate handling of structure, system, and component (SSC) performance or

condition problems;

(2) verify the appropriate handling of degraded SSC functional

performance;

(3) evaluate the role of work practices and common cause problems; and

-16-(4) evaluate the handling of SSC issues reviewed under the requirements of the Maintenance Rule, 10 CFR Part 50, Appendix B, and the TSs.*May 1, 2006: Units 1 and 2, Containment isolation valves

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

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

.1 Risk Assessments and Management of Risk

a. Inspection Scope

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

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

procedures prior to changes in plant configuration for maintenance activities and plant

operations;

(2) the accuracy, adequacy, and completeness of the information considered

in the risk assessment;

(3) that PG&E recognizes, and/or enters as applicable, the

appropriate risk category according to the risk assessment results and PG&E

procedures; and

(4) that PG&E identified and corrected problems related to maintenance risk assessments.*April 5, 2006: Unit 2; Diesel Fuel Oil Transfer Pump 0-1 and Electrohydraulic Pump 2-2 preventive maintenance, 500 kV Circuit Breaker 542 replacement, and

Morro Bay to Diablo Canyon 230 kV line outage due to fiber optic cable

installation.

Documents reviewed by the inspectors included Procedure AD7.DC6, "On-line Maintenance Risk Management," Revision 9.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.2 Emergent Work

a. Inspection Scope

The inspectors:

(1) verified that PG&E performed actions to minimize the probability of initiating events and maintained the functional capability of mitigating systems and

barrier integrity systems;

(2) verified that emergent work-related activities such as

-17-troubleshooting, work planning/scheduling, establishing plant conditions, aligning equipment, tagging, temporary modifications, and equipment restoration did not place

the plant in an unacceptable configuration; and

(3) reviewed the FSAR Update to

determine if PG&E identified and corrected risk assessment and emergent work control

problems.*April 2, 2006: Unit 1, Diesel Engine Generator 1-3 voltage regulator failure

• June 3, 2006: Unit 1, Failure of rod control system to manually withdraw Bank D control rods from core Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R14 Personnel Performance Related to Nonroutine Plant Evolutions and Events (71111.14)

a. Inspection Scope

The inspectors:

(1) reviewed operator logs, plant computer data, and/or strip charts for the below listed evolutions to evaluate operator performance in coping with nonroutine

events and transients;

(2) verified that operator actions were in accordance with the

response required by plant procedures and training; and

(3) verified that PG&E has

identified and implemented appropriate corrective actions associated with personnel

performance problems that occurred during the nonroutine evolutions sampled.*April 23, 2006: Unit 2, Fuel handling cart position resolver failed while a fuelassembly was in motion*May 4, 2006: Units 1 and 2, Magnitude 2.8 earthquake approximately 6 km west northwest of Diablo Canyon Power Plant*May 25, 2006: Unit 2, Auxiliary Transformer 2-1 sudden pressure trip

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

-18-The inspectors:

(1) reviewed plant status documents, such as operator shift logs, emergent work documentation, deferred modifications, and standing orders, to

determine if an operability evaluation was warranted for degraded components;

(2) referred to the FSAR Update and design bases documents to review the technical

adequacy of the operability evaluations;

(3) evaluated compensatory measures

associated with operability evaluations;

(4) determined degraded component impact on

any TS;

(5) used the significance determination process to evaluate the risk significance

of degraded or inoperable equipment; and

(5) verified that PG&E has identified and

implemented appropriate corrective actions associated with degraded components.*April 14, 2006: Unit 1, Condensate storage tank epoxy delamination*April 14, 2006: Unit 2, Residual heat removal system weld flaw

• May 8, 2006: Unit 2, Station vital inverters

• May 9, 2006: Units 1 and 2, Feedwater ultrasonic flow meter data scatter

• May 21, 2006: Unit 2, Accumulator 2-3 discharge line water hammer Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed five samples.

b. Findings

Introduction:

A self-revealing, NCV of 10 CFR Part 50, Appendix B, Criterion XVI, was determined for the failure of operators to promptly identify a condition adverse to quality.

Specifically, operators failed to document in the CAP an unexpected level drop in

Accumulator 1-3 during Refueling Outage 1R13. Failure to enter the occurrence into the

CAP precluded corrective actions that would have prevented the unexpected level drop

in Accumulator 2-3 and the water hammer of its discharge piping.

Description

On May 21, 2006, with Unit 2 in Mode 4 and reactor coolant system pressure at 935 psig, operators opened Accumulator 2-3 Discharge Valve SI-2-8808C

and subsequently Accumulator 2-3 level unexpectedly dropped from 67 to 57 percent.

At the same time, operators received a Reactor Coolant Pump 2-3 vibration alarm and

audible indications of a water hammer from inside containment. PG&E staff concluded

that a water hammer had occurred inside the discharge piping of Accumulator 2-3. As

immediate corrective actions, PG&E staff visually walked down Accumulator 2-3

discharge piping and supports, verified operability of the discharge piping seismic

snubbers, and verified the absence of voids in other portions of Units 1 and 2 emergency

core cooling system piping. Upon review of Accumulator 2-3 piping layout, PG&E staff

found that there were no vent points in the accumulator discharge piping between motor-

operated discharge Valve SI-2-8808C and discharge check Valve SI-2-8956C.

Additionally, there were no procedures that specifically addressed the venting of the

discharge line. The inspectors calculated approximately 83 feet of 10-inch pipe between

the two valves, which equated to an approximate volume of 34.7 ft

3. PG&E initiated a

root cause investigation under Nonconformance Report N0002207 to determine the

cause(s) and appropriate corrective actions for the water hammer event.

-19-While investigating the cause of the water hammer event, PG&E staff learned that a similar event had occurred with Accumulator 1-3 during Refueling Outage 1R13. On

November 27, 2005, operators opened Accumulator 1-3 Discharge Valve SI-1-8808C

and observed an approximate 7 percent level drop in the accumulator. However, there

were no corresponding indications of a water hammer, such as an audible noise or

reactor coolant pump vibration alarms. Although the level drop was recorded in the

operator logs, operators failed to enter the unexpected occurrence into the CAP. PG&E

staff has since entered the occurrence as AR A0669453.

The inspectors determined that the failure to address the Unit 1 accumulator level drop precluded corrective actions from being taken to prevent a recurrence of the event on

Unit 2. Specifically, PG&E staff should have identified the voided condition after the

Unit 1 accumulator level drop and that there was potential for voiding of the accumulator

discharge piping due to the absence of vent points and procedures for venting.

Analysis:

The performance deficiency associated with this finding involved a failure of operations personnel to promptly identify a condition adverse to quality and enter it into

the CAP. The performance deficiency was self-revealing based on the second event

initiating the licensee's review of the cause and subsequent identification that the event

had occurred on Unit 1 also. The finding is greater than minor because it is associated

with the Mitigating Systems Cornerstone attribute of configuration control and affects the

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

systems that respond to initiating events to prevent undesirable consequences. Using

the IMC 0609, "Significance Determination Process," Appendix A, Phase 1 Screening

Worksheet, the finding is determined to be of very low safety significance because the

finding did not represent a loss of safety function, an actual loss of a safety-related train

for greater than its TS allowed outage time, or screen as potentially risk-significant due

to seismic, fire, flooding, or severe weather initiating events. The finding had a

crosscutting aspect in the area of problem identification and resolution because

operations personnel failed to promptly identify, in the CAP, the unexpected level drop in

Accumulator 1-3.

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires, in part, that measures be established to assure that conditions adverse to quality are

promptly identified and corrected. Contrary to this, between November 27, 2005, and

May 24, 2006, operations personnel failed to assure that a condition adverse to quality

was promptly identified. Specifically, on November 27, 2005, the level in

Accumulator 1-3 unexpectedly dropped 7 percent when operators opened its discharge

valve. Although operators documented the event in their logs, they failed to enter the

occurrence into the CAP. Subsequently, no corrective actions were taken. On

May 21, 2006, when the discharge valve on Accumulator 2-3 was opened, its level

unexpectedly dropped by 10 percent and a water hammer occurred in its discharge

piping. The apparent cause of the failure to promptly identify a condition adverse to

quality was that operators did not recognize the significance of the Accumulator 1-3 level

drop. Corrective actions include additional training of operations personnel regarding

the importance of promptly identifying conditions adverse to quality. Because the finding

is of very low safety significance and has been entered into PG&E's CAP as

AR A0669468, this violation is being treated as an NCV consistent with Section VI.A of

-20-the Enforcement Policy: NCV 50-275/06-03-02, Failure to Promptly Identify Voiding in Accumulator Discharge Line.

1R17 Permanent Plant Modifications (71111.17)

a. Inspection Scope

The inspectors reviewed key affected parameters associated with energy needs, materials/replacement components, timing, heat removal, control signals, equipment

protection from hazards, operations, flowpaths, pressure boundary, ventilation boundary, structural, process medium properties, licensing basis, and failure modes for the one

modification listed below. The inspectors verified that:

(1) modification preparation, staging, and implementation did not impair emergency/abnormal operating procedure

actions, key safety functions, or operator response to loss of key safety functions;

(2) postmodification testing maintained the plant in a safe configuration during testing by

verifying that unintended system interactions will not occur, SSC performance

characteristics still met the design basis, the appropriateness of modification design

assumptions, and the modification test acceptance criteria has been met; and

(3) PG&E

has identified and implemented appropriate corrective actions associated with

permanent plant modifications. *May 19, 2006: Removal of mesh over the residual heat removal suction point in the containment recirculation sump and modifications to the reactor cavity door to

address recirculation sump debris loading concerns Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors selected the nine below listed postmaintenance test activities of risk-significant systems or components. For each item, the inspectors:

(1) reviewed the

applicable licensing basis and/or design basis documents to determine the safety

functions;

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

maintenance activity; and

(3) reviewed the test procedure to ensure it adequately tested

the safety function that may have been affected. The inspectors either witnessed or

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

evaluated, test equipment was calibrated, procedures were followed, jumpers were

properly controlled, the test data results were complete and accurate, the test equipment

was removed, the system was properly realigned, and deficiencies during testing were

documented. The inspectors also reviewed the FSAR Update to determine if PG&E

identified and corrected problems related to postmaintenance testing.

-21-*April 18, 2006: Unit 2, Containment Spray Pump 2-1 and 2-2*April 20, 2006: Unit 2, Source Range Nuclear Instrument 31

• May 2, 2006: Unit 2, Component Cooling Water Pump 2-3

• May 2, 2006: Unit 2, Vital Inverter IY-21

• May 2, 2006: Unit 2, 4kV Vital Bus "H" Switchgear

• May 5, 2006: Unit 2, Auxiliary Saltwater Pump 2-2

• May 11, 2006: Unit 2, Centrifugal Charging Pump 2-1

• May 12, 2006: Unit 2, Fuel transfer cart position resolver

• May 18, 2006: Unit 2, Auxiliary Transformer 2-1 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed nine samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Outage Activities (71111.20)

a. Inspection Scope

The inspectors reviewed the following risk-significant refueling items or outage activities to verify defense-in-depth commensurate with the outage risk control plan, compliance

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

of Decay Heat Removal":

(1) the risk control plan;

(2) tagging/clearance activities;

(3) RCS instrumentation;

(4) electrical power;

(5) decay heat removal;

(6) spent fuel pool

cooling;

(7) inventory control;

(8) reactivity control;

(9) containment closure;

(10) reduced

inventory or midloop conditions;

(11) refueling activities;

(12) heatup and cooldown

activities;

(13) restart activities; and

(14) identification and implementation of appropriate

corrective actions associated with refueling and outage activities. The inspectors'

containment inspections included observations of the containment sump for damage and

debris and supports, braces, and snubbers for evidence of excessive stress, water

hammer, or aging. Documents reviewed by the inspectors included the Unit 2 Refueling

Outage 2R13 Outage Safety Plan.

The inspectors completed one sample.

b. Findings

Introduction

An NRC-identified NCV of TS 5.4.1.a was determined for an inadequate procedure, Procedure OP A-2:II, "Reactor Vessel - Draining the RCS to the Vessel

Flange - With Fuel in Vessel," Revision 33A. Specifically, the procedure did not address

the reactor vessel level instrumentation required by the procedure deviated from actual

level by approximately 15 inches when the time to boiling in the reactor vessel was

approximately 20 minutes, if shutdown cooling were lost.

-22-Description

One action to ensure the integrity of shutdown cooling by operators was to prevent reactor vessel water level from dropping below the 107.5 foot elevation, where

vortexing of the shutdown cooling pumps may occur. To monitor reactor vessel water

level, operators used three RCS water level instruments when above 112 foot elevation.

The first level instrument was the wide-range reactor vessel refueling level instrument

system (RVRLIS), which consisted of two pressure transmitters measuring the

differential pressure across the RCS. The reference leg transmitter was located at the

top of the pressurizer and the variable leg transmitter was located at the Loop 4

crossover leg. The second level instrument was LI-400, which is a clear standpipe with

internal flags that indicate water level. LI-400 had essentially the same range and

instrument tap locations as wide-range RVRLIS. The third level instrument was the

narrow-range RVRLIS, which also consisted of two pressure transmitters that measured

the differential pressure across the upper portion of the reactor vessel. The reference

leg transmitter was located at the reactor head vent, and the variable leg transmitter was

located at the Loop 3 hot leg.

On April 20, 2006, in preparation for reactor vessel head removal, operators lowered water level in the reactor vessel to the 112 foot elevation (2 feet below the vessel flange)

using Procedure OP A-2:II. At the 112 foot elevation, the time for water in the reactor

vessel to boil, if shutdown cooling were lost, was reduced to approximately 20 minutes.

During the RCS draindown to the 112 foot elevation, Procedure OP A-2:II required

operators to maintain wide-range RVRLIS and LI-400 level indications in agreement by

+/- 9 inches. However, Procedure OP A-2:II did not require the instruments to agree

once level reached the 112 foot elevation. Additionally, Procedure OP A-2:II allowed

operators to place into service narrow-range RVRLIS and required it to read within

+/- 4 inches of LI-400 initially, but not for the duration of the RCS depressurization which

was to follow.

Once operators reached the 112 foot elevation and placed narrow-range RVRLIS in service, they began to depressurize the RCS according to Procedure OP A-2:II. During

the depressurization, operators observed that both required instruments, wide-range

RVRLIS and LI-400 began to show increasing level, while the optional narrow-range

RVRLIS water level remained stable at 112 feet. The deviation between narrow-range

RVRLIS and the other two instruments grew to approximately 15 inches before levels

stabilized. PG&E staff determined that a pressure differential existed between the gas

spaces of the pressurizer and reactor vessel. The RCS was depressurized via the

pressurizer relief tank with an approximate 1-inch outer diameter pipe. The

communication path between the pressurizer and reactor vessel gas spaces was also an

approximate 1-inch outer diameter pipe.

Despite the communication pathway, the depressurization activities would cause the pressurizer gas space to have a lower

pressure than the reactor vessel gas space. Subsequently, the wide-range RVRLIS and

LI-400 instruments would read lower (reference from the pressurizer gas space) than

narrow-range RVRLIS (referenced from the reactor vessel gas space).

The inspectors reviewed operating experience from both the Diablo Canyon Power Plant and the nuclear industry. Specifically, the inspectors reviewed Generic Letter 88-17, "Loss of Decay Heat Removal." Generic Letter 88-17 specifically addressed reduced

inventory evolutions, which is defined as 3 feet below the reactor vessel flange. While

the evolution on April 20, 2006, involved an RCS level that was only 2 feet below the

-23-reactor vessel flange, the time-to-boiling estimate was short (approximately 20 minutes).

Therefore, the inspectors determined that many of the recommendations in Generic

Letter 88-17 could be considered as operating experience for this evolution. An example

of a recommendation was the consideration of various phenomena that could affect level

instrumentation, including the inability of gas spaces to communicate if the RCS legs are

full of water. Also, Generic Letter 88-17 recommended reliable, accurate RCS water

level information for operators whenever approaching or operating in a condition where a

loss of level can lead to loss of decay heat removal. Through discussions with operators

and a review of Procedure OP A-2:II, the inspectors observed that Diablo Canyon Power

Plant had operating experience that would demonstrate that the level instrumentation

would tend to deviate when the RCS was being depressurzied.

The inspectors determined that PG&E staff had failed to adequately maintain Procedure OP A-2:II. First, wide-range RVRLIS and LI-400 were the required RCS level

instruments during the RCS depressurization at the 112 foot elevation, even though

these instruments would tend to read nonconservatively due to the pressure differences

in the gas spaces of the pressurizer and the reactor vessel. The inspectors determined

that an adequate review of operating experience would have demonstrated that these

level instruments were nonconservative for the depressurization evolution. Second, Procedure OP A-2:II did not have criteria regarding the performance of the RCS level

instruments during the RCS depressurization evolution. Although operators knew that

RCS level instruments may deviate from each other during the depressurization, there

was no criteria that would have given operators information that abnormal level

deviations were occurring and may be indicative of unexpected equipment operation, problems, or phenomenon. Generic Letter 88-17 had recommended that licensees

consider various phenomenon that could affect level instrumentation and that reliable

and accurate RCS level information be provided to the operator to the extent possible

when approaching conditions that could challenge loss of decay heat removal.

Analysis:

The performance deficiency associated with this finding involved the failure to maintain Procedure OP A-2:II. The finding is greater than minor because it is associated

with the Mitigating Systems Cornerstone attribute of procedure quality and affects the

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

systems that respond to initiating events to prevent undesirable consequences. Using

IMC 0609, Appendix G, Attachment 1, Checklist 3, the finding is determined to be of very

low safety significance since one set of instrumentation provided accurate RCS level

indication and there was no loss of RCS inventory control. The finding had a crosscutting aspect in the area of human performance for resources because PG&E

failed to ensure the adequacy of the procedures used for reactor vessel level monitoring

to ensure nuclear safety.

Enforcement

TS 5.4.1.a requires that written procedures be established, implemented, and maintained covering the activities specif ied in Appendix A, "Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors," of Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operation)," dated February 1978.

Regulatory Guide 1.33, Appendix A, Section 2, requires procedures for refueling

operations. Contrary to this, Procedure OP A-2:II, "Reactor Vessel - Draining the RCS

to the Vessel Flange - With Fuel in Vessel," was inadequate because the procedures

required the wide-range RVRLIS and LI-400 to be in service during RCS

-24-depressurization, despite operating experience that demonstrated these instruments would read nonconservatively. Additionally, Procedure OP A-2:II did not have criteria

that alerted operators to abnormal level instrument deviations that may be caused by

phenomena outside of the level deviations expected by the RCS depressurization.

PG&E has planned to evaluate potential changes to Procedure OP A-2:II and RCS water

level instrumentation when used during RCS depressurization. Because the finding is of

very low safety significance and has been entered into PG&E's CAP as ARs A0664484, A0672419, and A0672422, this violation is being treated as an NCV consistent with

Section VI.A of the Enforcement Policy: NCV 50-323/06-03-03, Inadequate Refueling

Procedure for Draining and Depressurizing the Reactor Coolant System.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors reviewed the FSAR Update, procedure requirements, and TS to ensure that the six below listed surveillance activities demonstrated that the SSC's tested were

capable of performing their intended safety functions. The inspectors either witnessed

or reviewed test data to verify that the following significant surveillance test attributes

were adequate:

(1) preconditioning;

(2) evaluation of testing impact on the plant;

(3) acceptance criteria;

(4) test equipment;

(5) procedures;

(6) jumpers;

(7) test data;

(8) testing frequency and method demonstrated TS operability;

(9) test equipment

removal;

(10) restoration of plant system s;

(11) fulfillment of ASME Code requirements;

(12) updating of performance indicator (PI) data;

(13) engineering evaluations, root

causes, and bases for returning tested SSCs not meeting the test acceptance criteria

were correct;

(14) reference setting data; and

(15) annunciators and alarm setpoints.

The inspectors also verified that PG&E identified and implemented any needed

corrective actions associated with the surveillance testing.*April 17, 2006: Unit 1, Procedure STP M-9I, "Diesel Generator Start and Load Tracking," Revision 19, and STP M-9A, "Diesel Engine Generator Routine

Surveillance Test," Revision 70*April 19, 2006: Unit 2, Procedures STP P-CSP-A22, "Comprehensive Testing of Containment Spray Pump 2-2," Revision 2 and STP P-CSP-A21, "Comprehensive Testing of Containment Spray Pump 2-1," Revision 1*May 1, 2006: Unit 2, Procedure STP 102, "Test of Backup Nitrogen Accumulator System to Spray Valves and Charging Valves 8145, 8146, and 8147,"

Revision 23*May 8, 2006: Unit 2, Procedure STP MP-I-7-T411H, "Control Bank D Rod Position Indication and Rod Stop C-11 Calibration," Revision 5A*May 8, 2006: Units 1 and 2, Procedure SP-312, "Security System Emergency Power Source and Load Transferring System," Revision 15B*May 16, 2006: Unit 2, Procedure STP 15, "Integrated Test of Engineered Safeguards and Diesel Generators," Revision 38A

-25-The inspectors completed six samples.

b. Findings

No findings of significance were identified.

===Cornerstone: Emergency Preparedness1EP4Emergency Action Level and Emergency Plan Changes (71114.04)

=

The inspectors performed in-office reviews of Revision 4, Change 5 to Section 4 of the Diablo Canyon, Units 1 and 2, Emergency Plan, and Revision 34 to Emergency Plan

Implementing Procedure EP G-1, "Emergency Classification and Emergency Plan

Activation," both submitted in February 2006.

These revisions changed emergency classification level descriptions and revised emergency action levels as described in NRC Bulletin 2005-002, "Emergency

Preparedness and Response Actions for Security-Based Events." These revisions were compared to their previous revisions, to the criteria of NUREG-0654, "Criteria for Preparation and Evaluation of Radiological Emergency

Response Plans and Preparedness in Support of Nuclear Power Plants," Revision 1; to

Nuclear Energy Institute (NEI) 99-01, "Methodology for Development of Emergency Action Levels," Revision 2; to NRC Bulletin 2005-02, and to the requirements of

10 CFR 50.47(b) and 50.54(q), to determine if PG&E adequately implemented

10 CFR 50.54(q).

This review was not documented in a Safety Evaluation Report and did not constitute the approval of licensee changes; therefore, these changes are subject to future inspection.

The inspectors completed two samples during this inspection.

b. Findings

No findings of significance were identified.1EP6Emergency Preparedness Evaluation (71114.06)

a. Inspection Scope

For drills contributing to drill/exercise performance and Emergency Response Organization PIs, the inspectors:

(1) observed the training evolution to identify any

weaknesses and deficiencies in classification, notification, and protective action

recommendation development activities;

(2) compared the identified weaknesses and

deficiencies against PG&E identified findings to determine whether PG&E is properly

identifying failures; and

(3) determined whether PG&E performance is in accordance

-26-with the guidance of the NEI 99-02, "Voluntary Submission of Performance Indicator Data," acceptance criteria.*June 1, 2006: A full drill involving a main steam line break, a steam generator tube rupture, and failed fuel cladding, including the turnover between two

emergency response organization crews*June 9, 2006: A simulator-based drill involving a main steam line break where a PI opportunity for classification of Notice of Unusual Event 28 existed Documents reviewed by the inspectors included the Diablo Canyon Power Plant Emergency Plan, Revision 4, and Lesson R061S5, "Imminent PTS," Revision 0.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.2.RADIATION SAFETY

===Cornerstone: Occupational Radiation Safety2OS1Access Control to Radiologically Significant Areas (71121.01)

=

This area was inspected to assess PG&E's performance in implementing physical and administrative controls for airborne radioactivity areas, radiation areas, high radiation

areas, and worker adherence to these controls. The inspectors used the requirements

in 10 CFR Part 20, the TSs, and PG&E's procedures required by TSs 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:*PI events and associated documentation packages reported by PG&E in the Occupational Radiation Safety Cornerstone *Controls (surveys, posting, and barricades) of radiation, high radiation, and airborne radioactivity areas *Radiation work permits, procedures, engineering controls, and air sampler locations *Conformity of electronic personal dosimeter alarm setpoints with survey indications and plant policy, and workers' knowledge of required actions when

their electronic personnel dosimeter noticeably malfunctions or alarms

-27-*Barrier integrity and performance of engineering controls in airborne radioactivity areas*Physical and programmatic controls for highly activated or contaminated materials (nonfuel) stored within spent fuel and other storage pools*Self-assessments, audits, licensee event reports, and special reports related to the access control program since the last inspection *Corrective action documents related to access controls

• Radiation work 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*Changes in licensee procedural controls of high dose rate - high radiation areas and very high radiation areas*Controls for special areas that have the potential to become very high radiation areas during certain plant operations*Posting and locking of entrances to all accessible high dose rate - high radiation areas and very high radiation areas*Radiation worker and radiation protection technician performance with respect to radiation protection work requirements The inspectors completed 19 samples.

b. Findings

Introduction

The inspectors identified a noncited violation of 10 CFR 20.1501(a)because PG&E failed to perform a survey to identify the magnitude and extent of radiation levels for radiological hazards. The violation had very low safety significance.

Description

On April 18, 2006, the inspectors toured the 100-foot elevation of the Unit 2 auxiliary building and identified elevated radiat ion levels near Chemical Volume Control System Valves CVCS-2-8502 and CVCS-2

-8512A. Subsequent surveys by PG&E confirmed radiation levels of up to 200 millirem per hour on contact and 28 millirem per hour at 30 centimeters in this area. From a review of a previous survey map, the inspectors noted that the highest general area radiation level in the area was

approximately 5 millirem per hour. Unit 2 began a plant evolution (RCS forced oxygenation) that had the potential to raise radiation levels in several areas of the unit.

Due to the forced oxygenation process, PG&E implemented their posting guides and

restricted personnel access to high radiation areas in Unit 2 that had potentially higher-

-28-than-normal radiation levels. However, PG&E did not restrict personnel access to radiation areas or survey a hallway on the 100-foot elevation that had the potential for higher-than-normal radiation levels prior to allowing personnel to enter them. PG&E's

posting guides did not address any actions that needed to be implemented for radiation

areas or the hallways of the 100-foot elevation. The inspectors determined that PG&E

failed to survey the area to determine the magnitude and extent of the radiation levels

and to evaluate the radiological hazards prior to allowing personnel to enter the area and

whether the posting guides communicated any required action.

Analysis:

The failure to survey is a performance deficiency. The finding was greater than minor because it was associated with the Occupational Radiation Safety

Cornerstone attribute of Exposure Control and Monitoring and affected the cornerstone

objective to ensure the adequate protection of a worker's health and safety from

exposure to radiation because workers could have unknowingly received additional

radiation exposure from the increase in radiation levels. Because the finding involved

the potential for unplanned, unintended dose resulting from conditions that were contrary

to NRC regulations, the finding was evaluated using the Occupational Radiation Safety

Significance Determination Process. The finding was determined to be of very low

safety significance because:

(1) it did not involve as low as reasonably

achievable (ALARA) planning or work controls,

(2) there was no personnel

overexposure,

(3) there was no substantial potential for personnel overexposure, and

(4) the finding did not compromise PG&E's ability to assess dose. The finding had

crosscutting aspects associated with human performance because adequate resources

were not established for the survey requirements.

Enforcement

10 CFR 20.1501(a) requires that each licensee make or cause to be made surveys that may be necessary to comply with the regulations in Part 20 to

determine the extent and magnitude of radiation levels and to evaluate the radiological

hazards. Pursuant to 10 CFR 20.1003, survey means an evaluation of the radiological

conditions and potential hazards incident to the production, use, transfer, release, disposal, or presence of radioactive material or other sources of radiation. Contrary to

this requirement, on April 18, 2006, PG&E failed to survey the 100-foot elevation of the

Unit 2 auxiliary building to assure compliance with 10 CFR 20.1201, which limits

radiation exposure to occupational workers to 5.0 rem total effective dose equivalent.

This violation was entered into PG&E's CAP as AR 0665039. Because this finding is of

very low safety significance and was entered into PG&E's CAP, it is being treated as an

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

NCV 50-323/06-03-04, Failure to Survey to Identify the Magnitude and Extent of

Radiation Levels to Identify Radiological Hazards.2OS2ALARA Planning and Controls (71121.02)

a. Inspection Scope

The inspectors assessed PG&E's performance with respect to maintaining individual and collective radiation exposures ALARA. The inspectors used the requirements in 10 CFR

Part 20 and PG&E's procedures required by TS as criteria for determining compliance.

The inspectors interviewed PG&E personnel and reviewed:

-29-*Five (to 10) outage or on-line maintenance work activities scheduled during the inspection period and associated work activity exposure estimates which were

likely to result in the highest personnel collective exposures *ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements *Integration of ALARA requirements into work procedure and radiation work permit documents *Person-hour estimates provided by maintenance planning and other groups to the radiation protection group with the actual work activity time requirements *Dose rate reduction activities in work planning

• Workers use of the low dose waiting areas

• First-line job supervisors' contribution to ensuring work activities are conducted in a dose efficient manner*Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas *Self-assessments, audits, and special reports related to the ALARA program since the last inspection The inspectors completed nine samples.

b. Findings

No findings of significance were identified.4.

4OA1 PI Verification

.1 Cornerstone:

Occupational Radiation Safety*Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors reviewed PG&E's documents from January 1 through March 31, 2006.

The review included corrective action documentation that identified occurrences in

locked high radiation areas (as defined in PG&E's TS), very high radiation areas (as

defined in 10 CFR 20.003), and unplanned personnel exposures (as defined in

NEI 99-02). Additional records reviewed included ALARA records and whole body

counts of selected individual exposures. The inspectors interviewed PG&E personnel

who were accountable for collecting and evaluating the PI data. In addition, the

-30-inspectors toured plant areas to verify that high radiation, locked high radiation, and very high radiation areas were properly controlled. PI definitions and guidance contained in

NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 3, were used to verify

the basis in reporting for each data element.

The inspectors completed one sample in this cornerstone.

b. Findings

No findings of significance were identified.

.2 Cornerstone:

Public Radiation Safety*Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences

a. Inspection Scope

The inspectors reviewed PG&E's documents from January 1 through March 31, 2006.

PG&E's records reviewed included corrective action documentation that identified

occurrences for liquid or gaseous effluent releases that exceeded PI thresholds and

those reported to the NRC. The inspectors interviewed PG&E personnel who were

accountable for collecting and evaluating the PI data. PI definitions and guidance

contained in NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 3, were

used to verify the basis in reporting for each data element.

The inspectors completed one sample in this cornerstone.

b. Findings

No findings of significance were identified.4OA2Identification and Resolution of Problems (71152)

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a daily screening of items entered into PG&E's CAP. This assessment was accomplished by reviewing ARs and event trend reports and attending

daily operational meetings. The inspectors:

(1) verified that equipment, human

performance, and program issues were being identified by PG&E at an appropriate

threshold and that the issues were entered into the CAP;

(2) verified that corrective

actions were commensurate with the significance of the issue; and

(3) identified

conditions that might warrant additional follow-up through other baseline inspection

procedures.

-31-

b. Findings

No findings of significance were identified.

.2 Selected Issue Follow-Up Inspection

a. Inspection Scope

In addition to the routine review, the inspectors selected the one below listed issue for a more in-depth review. The inspectors considered the following during the review of

PG&E'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.*April 26, 2006: High Stator Temperature Trends on Component Cooling Water Motors Documents reviewed by the inspectors are listed in the attachment.

b. Findings

No findings of significance were identified.

.3 Semiannual Trend Review

a. Inspection Scope

The inspectors completed a semiannual trend review of repetitive or closely-related issues that were documented in ARs, system and component health reports, quality

assurance audits, trend reports, Diablo Canyon internal PIs, and NRC inspection reports

to identify trends that might indicate the existence of more safety-significant issues. The

inspectors' review consisted of the 6-month period of January 1 to June 30, 2006. When

warranted, some of the samples expanded beyond those dates to fully assess the issue.

The inspectors also reviewed CAP items associated with troubleshooting. The

inspectors compared and contrasted their results with the results contained in PG&E's

quarterly trend reports. Corrective actions associated with a sample of the issues

identified in PG&E's trend report were reviewed for adequacy. Documents reviewed by

the inspectors are listed in the attachment.

b. Findings

The inspectors reviewed Quality Verification Assessment 060480001, "Troubleshooting,"

dated April 14, 2006. The purpose of the assessment was to evaluate the

implementation of the troubleshooting program as described in Procedure MA1.DC10, "Troubleshooting," Revision 9. Quality Verification identified a need for improvement in

documentation of problem statements, data acquisition results, determination of possible

-32-failure modes, troubleshooting plans, and analysis of results. In particular, maintenance personnel's implementation of the troubleshooting procedure often did not meet the

troubleshooting attributes, while engineering personnel's implementation of

troubleshooting had only minor inconsistencies. Furthermore, the assessment observed

the need for improvement in the knowledge of troubleshooting requirements throughout

the organization for:

(1) when troubleshooting should be implemented,

(2) what types of

equipment problems require troubleshooting, and

(3) the level of planning and

documentation required for low level equipment problems. Quality verification found that

Procedure MA1.DC10 continued to be difficult to use despite revisions to the procedure.

The inspectors also reviewed previous Quality Verification assessments, dating back to 2004, for troubleshooting observations. These assessments are listed in the

attachment. While the assessments pointed out that the site has shown improvement in troubleshooting efforts since 2003, the inspectors observed that Quality Verification had

previously identified similar issues as those discussed above. The following are some

insights from previous assessments, which also covered previous revisions to

Procedure MA1.DC10.*In some instances, initial troubleshooting efforts failed to identify the cause of the problem for safety-related and/or risk-significant equipment.*On several occasions, the site was reluctant to enter a more rigorous/formal troubleshooting format, since it was seen as time consuming and the technicians

felt they knew better on how to approach the problem as opposed to following

Procedure MA1.DC10. As a result, there were instances where the cause

determination was inaccurate, such as the case with Containment Spray

Pump 2-2 control cable ground.*Procedure MA1.DC10 was deficient, making it difficult for maintenance personnel to comply with its requirements. Subsequently, personnel performing

troubleshooting relied upon their knowledge and experience to the exclusion of

the requirements in the troubleshooting procedure.*In some instances, maintenance and engineering personnel were reluctant to characterize work activities as "troubleshooting" when in fact the activities

involved the investigation of plant equipment problems. Quality Verification

recommended that senior management emphasize the expectations for

implementing Procedure MA1.DC10 when the criteria for entering the procedure

were met.*Quality Verification noted that the level of detail in troubleshooting documentation was weak. For example, as-found conditions were not documented, results of a

component history search were not documented, and documentation of work

performed was not detailed.

The inspectors have observed several troubleshooting activities that have occurred on site and, in general, agree with the assessments identified by Quality Verification. Most

recently, the inspectors observed troubleshooting for AFW Discharge

Valves FW-1-LCV-107 and FW-1-LCV-108, as described in Section

4OA5 of this report.

-33-The inspectors observed that troubleshooting for Valve FW-1-LCV-107 was performed by maintenance personnel. In reviewing the documentation from that troubleshooting

effort, the inspectors could not identify any other possible failure mechanisms that had

been considered by Maintenance personnel other than the determined cause.

Additionally, the inspectors observed data that would tend to contradict the determined

cause of the valve, as described in Section 4OA5. The inspectors also observed

troubleshooting for Valve FW-1-LCV-108, which had similar indications as Valve

FW-1-LCV-107 when it failed to stroke. The troubleshooting team consisted of both

Engineering and Maintenance personnel. The inspectors observed that the Engineering

personnel were careful to:

(1) preserve evidence by arranging the various investigative

activities,

(2) consider various potential failu re mechanisms before investigative activities began, and

(3) consider all data available to them. In summary, the inspectors felt that

the observations made during the troubleshooting on Valves FW-1-LCV-107

and FW-1-LCV-108 confirmed the observations documented by Quality Verification in their assessments.

.4 Occupational Radiation Safety

a. Inspection Scope

The inspectors evaluated the effectiveness of PG&E's problem identification and resolution process with respect to the following inspection areas:*Access Control to Radiologically Significant Areas (Section 2OS1)*ALARA Planning and Controls (Section 2OS2)

b. Findings

No findings of significance were identified.

.5 Inservice Inspection

a. Inspection Scope

The inspector reviewed the related condition reports on an inservice inspection issued during the current and past refueling outages and verified that PG&E identified, evaluated, corrected, and trended problems. The inspector evaluated the effectiveness

of PG&E's CAP, including the adequacy of the technical resolutions.

b. Findings

No findings of significance were identified.

-34-4OA3Event Followup (71153)

.1 Main Turbine Trip Due to Personnel Error

a. Inspection Scope

On June 7, 2006, the inspector reviewed the actions taken prior to, during, and following a main turbine trip on Unit 2, on May 25, 2006. Operations personnel were attempting to

parallel the main generator to the grid during the reactor startup, following a refueling

outage.

b. Findings

No findings of significance were identified.

.2 (Closed) Licensee Event Report 50-275/1-2005-001-00 Steam Generator Tube Plugging

Because of Stress Corrosion Cracking On November 11, 2005, PG&E determined that analysis of eddy current testing on Steam Generators 1-1 and 1-2 indicated that greater than one percent of the tubes were

defective as a result of outside diameter stress corrosion cracking at the hot leg tube

support plates and at the hot leg top of tubesheet. This determination occurred at the

end of Operating Cycle 13. The inspector verified that PG&E took effective corrective

action. All defective tubes were plugged and removed from service in accordance with

TS 5.5.9, "Steam Generator (SG) Tube Surveillance Program." The licensing basis accident analysis assumes a tube plugging limit of 15 percent per steam generator. The

plugging percentage for each Unit 1 steam generator remains within the current

allowable limit of 15 percent. Steam Generator 1-1 has 6.8 percent plugged and Steam

Generator 1-2 has 9.3 percent plugged. PG&E maintains a comprehensive program to

minimize steam generator tube degradation and plans to replace the steam generators

at the end of Operating Cycle 15. This licensee event report is closed.

4OA5Other

.1 TI 2515/160 - Pressurizer Penetration Nozzles and Steam Space Piping Connections in

U.S. Pressurized Water Reactors

a. Inspection Scope

The inspectors reviewed PG&E's actions regarding the inspection and repair associated with Alloy 82/182/600 material that may have been used in pressurizer penetration

nozzles, steam space piping connections, heads, and shells. Specifically, the inspectors

reviewed PG&E's response to NRC Bulletin 2004-01, "Inspection of Alloy 82/182/600

Materials Used in the Fabrication of Pressurizer Penetrations and Steam Space Piping

Connections at Pressurized Water Reactors." PG&E documented in their response to

the bulletin that the Unit 2 pressurizer utilized Alloy 82/182 material in the nozzle to safe

end welds for the surge line, the pressurizer safety lines, the power-operated relief valve

-35-lines, and the spray line. Stainless steel was used in all other pressurizer penetration welds. In PG&E's response to the bulletin, they committed to a bare metal visual exam

of all the welds that had Alloy 82/182 material.

The inspectors reviewed PG&E's response to NRC Bulletin 2004-01 and observed their inspection activities for the Unit 2 pressurizer. The inspectors verified the qualifications

of personnel performing the bare metal exam and independently observed several of the

subject pressurizer penetration welds for evidence of boric acid deposits and the

capability to perform the bare metal exam. The inspectors reviewed Procedure ISI VT 2-1, "Visual Examination During Section XI System Pressure Test,"

Revision 0, during the inspection.

The activities required in Temporary Instruction (TI) 2515/160 for Diablo Canyon Power Plant Unit 2 have been completed. Documents reviewed by the inspectors are listed in

the attachment. This TI is closed for Unit 2.

b. Findings

No findings of significance were identified.

.2 TI 2515/165 - Operational Readiness of Offsite Power and Impact on Plant Risk

a. Inspection Scope

The objective of TI 2515/165, "Operational Readiness of Offsite Power and Impact on Plant Risk," is to gather information to support the assessment of nuclear power plant

operational readiness of offsite power systems and impact on plant risk. During this

inspection, the inspectors interviewed PG&E personnel, reviewed applicable procedures, and gathered information for further evaluation by the Office of Nuclear Reactor

Regulation.

b. Findings

No findings of significance were identified.

.3 (Closed) Unresolved Item (URI) 05000275/05-05-03:

Corrective Actions to Prevent Repetitive Failures of AFW Limitorque Valves

a. Inspection Scope

The inspectors performed additional inspection associated with this URI to determine any performance issues associated with design and maintenance practices regarding

Limitorque actuators. The inspectors also evaluated any extent of condition and/or

generic impacts.

b. Findings

Introduction

A Green, NRC-identified NCV was identified for the failure to correct a significant condition adverse to quality as required by 10 CFR Part 50, Appendix B,

-36-Criterion XVI, "Corrective Action." Specifically, PG&E failed to preclude repetition of similar failures with Limitorque Model SMB-000 motor-operated valves in the AFW

system. The failure of these motor-operated valves affected the ability of the valves to

be operated from the control room and the hot shutdown panel. These valves are

required to shut in the event of a faulted steam generator or to prevent overfilling of a steam generator.

Description

The AFW system is an engineered safety feature system that is directly relied upon to prevent core damage and RCS overpressurization in the event of

transients, such as a loss of normal feedwater or secondary system pipe rupture. It also

provides a means for plant cooldown following any plant transient.

Motor-operated Valves FW-1-LCV-107, FW-1-LCV-108, and FW-1-LCV-109 are discharge isolation valves associated with the turbine-driven AFW pump. On

March 15, 2003, Valve FW-2-LCV-109 failed to close during routine surveillance testing.

Operators failed to preserve the faulted condition by remotely opening the valve, manually stroking the valve, removing the actuator cover and inspecting the contacts, and burnishing the close torque contacts. Because the failure was not repeated during

troubleshooting, PG&E staff determined that it was not a maintenance preventable

functional failure. However, PG&E staff identified in AR A0578562 that this was a critical

component failure that should be prevented from recurring per Procedure ER1.ID1, "Equipment Reliability Process," Revision 1.

On August 20, 2004, Valve FW-1-LCV-107 failed to operate after corrective maintenance. PG&E staff identified in AR A0616766 that this failure was a maintenance

preventible functional failure and directed staff to implement actions to prevent

recurrence. The corrective action identified was to revise Procedure MP E-53.10A, "Preventive Maintenance of Limitorque Operators," to include steps to burnish the torque

switch contacts, since the cause of the valve to stroke was determined to be corrosion.

On November 3, 2005, operators were performing a functional test of Valve FW-1-LCV-107 per Procedure STP V-2U2D, "Exercising S/G No. 2 AFW Supply

Valves LCV-107 and LCV-108," Revision 4, after valve packing had been replaced.

Motor-operated Valve FW-1-LCV-107 had been stroked open and closed successfully

from the control room. Operational control for the valve was then transferred to the Hot

Shutdown Panel, the valve was opened and not able to be shut. A second attempt to

shut the valve was unsuccessful. Records of the subsequent visual inspection indicated

that the contact fingers were coated with debris, but not the contact surfaces.

Maintenance records also indicated that the actuator cover was removed and the torque

switch contacts were burnished. The valve was declared operable after several

successful operations. PG&E staff identified this problem in AR A0650104 and again

directed that this problem be prevented from recurring.

On February 2, 2006, a similar failure occurred with Valve FW-1-LCV-108. This valve also had successful operations following maintenance with a subsequent failure.

Troubleshooting by PG&E staff determined that the torque limit switch contacts had high

resistance. During troubleshooting efforts, the inspectors observed that the contact

switch housing cover for the Limitorque Model SMB-000 actuators had been modified to

allow them to fit over the contact assembly more easily. The inspectors also observed

-37-that, even with the modified cover, the installation and removal of the close-fitting cover rubbed against the wires. PG&E troubleshooting personnel determined that the screws

would loosen if the wires leading to the torque switch were moved.

The inspectors verified that the installation of the cover and potential for screw loosening by wire movement could contribute to valves failing to actuate, which had not been

previously evaluated by PG&E staff as a possible contributor to the failures of

Valve FW-1-LCV-107. PG&E initiated a root cause evaluation into the failure of the

Model SMB-000 actuators (Nonconformance Report NCR N0002205) and identified

organizational deficiencies in the failure analysis of critical components as the root

cause. The root cause determined that PG&E staff failed to account for maintenance

practices, latent design issues, or environmental effects other than corrosion to prevent

repeat failures of Model SMB-000 actuators.

The inspectors determined that PG&E staff failed to promptly identify and correct a significant condition adverse to quality. Specifically, the inspectors determined that

PG&E failed to adequately troubleshoot the failures of Valve FW-1-LCV-107. During the

inspection, data such as:

(1) the failure of the valves to stroke after one or more

successful strokes,

(2) the conductance capability of the silver torque switch contacts

with corrosion,

(3) the orientation of the torque switch contacts, and

(4) an already

present step in the maintenance procedure to clean the torque switch contacts lead the

inspectors to question the troubleshooting conclusion of debris or corrosion on the

torque switch contacts. Furthermore, the troubleshooting results from

Valve FW-1-LCV-108 reduced the likelihood of debris or corrosion as a possible failure

mechanism. The inspectors determined that, with the history of similar failures of these

type of valve actuators, along with the si gnificance of the system, PG&E should have initiated a root cause evaluation earlier with the Valve FW-1-LCV-107 failures to prevent

recurrence of the problem.

Analysis:

The performance deficiency associated with this finding was the failure to promptly identify and correct a significant condition adverse to quality associated with

the AFW motor-operated discharge valves. The finding is greater than minor because it

is associated with the Mitigating Systems Cornerstone attribute of equipment

performance and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent

undesirable consequences. Using the IMC 0609, "Significance Determination Process,"

Phase 1 Worksheet, the finding is determined to be of very low safety significance

because it did not represent an actual loss of safety function, represent an actual loss of

safety function for a single train for greater than the TS allowed outage time, or screen

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

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

resolution since PG&E staff failed to adequately trend, assess, and troubleshoot

previous Limitorque SMB-000 actuator failures.

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI, states, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and

nonconformances, are promptly identified and corrected. In the case of significant

conditions adverse to quality, the measures shall assure that the cause of the condition

-38-is determined and corrective action taken to preclude repetition. Contrary to this, from 2003 to 2006, PG&E staff failed to identify and implement adequate corrective actions to

prevent recurrence of turbine-driven AFW Limitorque SMB-000 actuator failures. Since

failure to identify and prevent recurrence of a significant condition adverse to quality was

determined to be of very low safety significance and has been entered into the CAP as

Nonconformance Report N0002205, this violation is being treated as a NCV, consistent

with Section VI.A of the NRC Enforcement Policy: NCV 50-275/06-03-05, Failure to

Prevent Recurrence of Limitorque Model SMB-000 Failures.40A6Management Meetings

Exit Meeting Summary

On April 6, 2006, the inspectors discussed the inspection results of licensed operator requalification with Mr. David Burns, Operations Training Supervisor. PG&E

acknowledged the findings presented. The inspectors asked PG&E if any materials

examined during the inspection should be considered proprietary. No proprietary

information was identified.

On April 10, 2006, the inspectors conducted a telephonic exit meeting to present the inspection results on Emergency Action Level and Emergency Plan Changes to

Mr. R. Waltos, Supervisor, Emergency Planning, who acknowledged the findings. The

inspectors confirmed that proprietary info rmation was not provided or examined during the inspection.

The inspector presented the results of the inservice inspection effort to Mr. J. Becker, Vice President Diablo Canyon Operations and Station Director, and other members of

PG&E management on May 3, 2006. PG&E management acknowledged the inspection

findings. During the inspection, the inspector asked if any materials examined should be

considered proprietary. Several documents were identified as proprietary information by

PG&E. The inspector informed PG&E that copies of those documents would be

destroyed after their review.

On May 4, 2006, the inspectors presented the occupational radiation safety inspection results to Mr. J. Becker, Vice President Diablo Canyon Operations and Station Director, and other members of the staff who acknowledged the findings. The inspectors

confirmed that proprietary information was not provided or examined during the inspection.

The resident inspection results were presented on July 12, 2006, to Mr. J. Becker, Vice President Diablo Canyon Operations and Station Director, and other members of PG&E

management. PG&E acknowledged the findings presented. The inspectors asked

PG&E whether any materials examined during the inspection should be considered

proprietary. No proprietary information was reviewed by the inspectors.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

PG&E personnel

J. Becker, Vice President - Diablo Canyon Operations and Station Director

S. David, Manager, Operations

J. Fledderman, Director, Site Services

R. Hite, Manager, Radiation Protection

D. Jacobs, Vice President - Nuclear Services

S. Ketelsen, Acting Director, Nuclear Quality, Analysis, and Licensing

K. Peters, Director, Engineering Services

J. Purkis, Director, Maintenance Services

P. Roller, Director, Operations Services

D. Taggart, Manager, Quality Verification

R. Waltos, Supervisor, Emergency Planning

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed50-323/06-03-01NCVFailure to Follow Welding Procedures (Section 1R08)50-275/06-03-02NCVFailure to Promptly Identify Voiding in Accumulator

Discharge Line (Section 1R15)50-323/06-03-03NCVInadequate Refueling Procedure for Draining and

Depressurizing the Reactor Coolant System

(Section 1R20)50-323/06-03-04NCVFailure to Survey to Identify the Magnitude and Extent of

Radiation Levels to Identify Radiological Hazards

(Section 2OS1)50-275/06-03-05NCVFailure to Prevent Recurrence of Limitorque Model

SMB-000 Failures (Section 4OA5.3)

Closed

05000275/2005-05-03URICorrective Actions to Prevent Repetitive Failures of

Auxiliary Feedwater Limitorque Valves

A-250-275/1-2005-001-00LERSteam Generator Tube Plugging Because of Stress

Corrosion Cracking (Section 4OA3.1)