ML080440436: Difference between revisions

Surge Nozzle to Safe End Weld, 02-005-031

PT/UT

Shutdown Cooling Piping 10" SCH 140

Pipe-Valve, 02-059-008

PT/UT

Shutdown Cooling Piping 16" SCH 160

Pipe-Elbow, 02-059-002

PT/UT

ENCLOSURE 2

-10-

Shutdown Cooling piping 16" SCH 160

Pipe-Valve, 02-059-001

PT/UT

Snubber, 02-052-110

VT3

The inspectors reviewed the following NDEs through record review:

System

Component/Weld ID

Exam Type

Y-Stop Valve, 02-021-068

VT3

Y-Stop Valve, 02-021-081

VT3

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

VT3

Feedwater

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

VT3

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

UT

The inspectors observed the initial Ultrasonic Examination System calibration for the

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

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

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

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

stainless steel piping were appropriately qualified.

The inspectors reviewed the NDE personnel qualification records for those contractor

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

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

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

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

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

Qualification and Certification of Nondestructive Testing Personnel, 1995 Edition.

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

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

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

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

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

steel weld identified as follows:

System

Component/Weld Identification

Pressurizer Surge

Line Nozzle-to-Safe

End-to-Pipe

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

Tungsten Arc Welding (machine)

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

requirements and licensee commitments.

ENCLOSURE 2

-11-

Welder qualification documentation packages and welder maintenance logs were

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

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

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

of the ASME code.

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

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

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

reviewed the welding procedure specifications and their corresponding procedure

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

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

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

the welding procedure specifications.

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

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

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

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

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

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

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

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

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

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

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

the welding procedure specification.

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

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

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

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

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

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

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

personnel qualification records for the examiner performing the examination were

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

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

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

the inspectors reviewed the Ultrasonic Examination Report of the ultrasonic examination

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

of 0.30 inches at the examination time.

ENCLOSURE 2

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

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

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

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

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

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

The inspection procedure required inspection of any augmented or industry initiation

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

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

b.

Findings

No findings of significance were identified.

.2

Vessel Upper Head Penetration (VUHP) Inspection Activities

a.

Inspection Scope

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

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

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

System

Component/Weld Identification

Examination Method

CEDM 87

UT/ET

CEDM 88

UT/ET

CEDM 79

UT/ET

CEDM 68

UT/ET

CEDM 60

UT/ET

CEDM 28

UT/ET

CEDM 78

UT/ET

CEDM 86

UT/ET

ICI 96

UT/ET

ICI 95

UT/ET

ICI 94

UT/ET

ICI 93

UT/ET

RVUH vent line

UT/ET

ENCLOSURE 2

-13-

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

EA-03-009.

b.

Findings

No findings of significance were identified.

.3

Boric Acid Corrosion Control Inspection (BACC) Activities

a.

Inspection Scope

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

inspections emphasized locations where boric acid leaks can cause degradation of

safety significant components.

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

coolant system piping components during the walkdown. The inspectors reviewed

licensee procedures governing the boric acid corrosion control program and inspector

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

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

determined whether components that exhibited leakage during the current outage had

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

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

descriptions, and the resulting Action Requests.

Component Number

Description

Action Request

2HV0512

Pressurizer surge line sample

isolation valve

070500261

2HV9203

Charging line insolation valve

071101172

2HV9201

Charging auxiliary spray

isolation valve

071101173

2HV9339

Shutdown cooling isolation

valve

070500262

2HV9326

Shutdown injection tank drain

valve

070500265

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

were identified during walkdowns.

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

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

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

walkdowns.

ENCLOSURE 2

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b.

Findings

No findings of significance were identified.

.4

Steam Generator Tube Inspection Activities

a.

Inspection Scope

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

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

from the EPRI examination technique specification sheets. It further specified

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

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

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

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

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

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

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

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

criteria. This review determined that the remaining screening parameters were

consistent with the EPRI and Combustion Engineering Owners Group guidelines.

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

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

qualifying EPRI examination technique specification sheets to verify that the essential

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

been identified and qualified through demonstration. The inspector reviewed acquisition

technique and analysis technique sheets are identified in the attachment.

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

flaws detected during the current outage against the previous outage operational

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

compared the previous outage operational assessment predictions contained in

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

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

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

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

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

No new damage mechanisms had been identified during this inspection.

The inspection procedure specified confirmation that the steam generator tube eddy

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

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

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

licensees degradation assessment report. The inspectors compared the recommended

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

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

ENCLOSURE 2

-15-

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

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

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

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

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

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

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

cold legs, rows 1-3

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

100 percent of all tubes

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

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

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

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

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

hot), 100 percent of sleeved tubes

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

Tube R28-C60 only

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

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

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

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

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

inspection)

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

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

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

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

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

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

examined with the 600UL bobbin probe due to restriction

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

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

including operating concerns and had taken appropriate corrective actions before plant

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

mechanisms.

ENCLOSURE 2

-16-

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

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

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

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

scope of inspection and were being inspected.

The inspection procedure further requires verification that repair processes being used

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

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

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

process.

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

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

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

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

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

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

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

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

inspection procedure requires verification that the licensee had identified a reasonable

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

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

because this condition did not exist.

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

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

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

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

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

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

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

travel speed was in accordance with procedural requirements. The inspectors

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

are identified in the attachment.

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

procedure specified confirmation that the licensee had taken or planned appropriate

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

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

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

inspection, no foreign material had been identified.

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

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

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

adequacy was questionable.

ENCLOSURE 2

-17-

b.

Findings

No findings of significance were identified.

.5

Identification and Resolution of Problems

a.

Inspection Scope

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

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

appropriateness of the corrective actions.

The inspector reviewed corrective action reports which dealt with inservice inspection

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

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

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

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

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

experience.

b.

Findings

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

completing all required inspection activities.

1R11

Licensed Operator Requalification (71111.11)

.1

Quarterly Inspection

a.

Inspection Scope

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

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

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

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

by the inspectors are listed in the attachment.

The inspectors completed one sample.

b.

Findings

No findings of significance were identified.

.2

Annual Inspection

a.

Inspection Scope

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

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

ENCLOSURE 2

-18-

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

were consistent with NUREG 1021, Operator Licensing Examination Standards for

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

Requalification Human Performance Significance Determination Process,

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

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

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

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

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

This individual was successfully remediated prior to returning to shift.

The inspector completed one sample.

b.

Findings

No findings of significance were identified.

1R12

Maintenance Effectiveness (71111.12)

a.

Inspection Scope

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

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

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

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

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

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

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b.

Findings

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

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

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

voltage regulator deficiencies should have placed the EDGs into maintenance rule

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

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

maintain system reliability.

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

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

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

which made them susceptible to dirt intrusion.

ENCLOSURE 2

-19-

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

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

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

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

subsequently upgraded to sealed multiturn gold plated potentiometers. The upgraded

installations were completed on August 26, 2007.

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

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

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

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

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

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

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

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

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

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

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

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

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

successfully complete the goal.

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

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

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

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

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

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

because the performance deficiency did not cause the degraded equipment

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

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

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

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

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

the failed EDG AVR.

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

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

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

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

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

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

being effectively controlled through appropriate preventive maintenance, such that the

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

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

the EDGs was being effectively controlled through appropriate preventive maintenance

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

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

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

ENCLOSURE 2

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

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

Maintenance Rule Requirements for Emergency Diesel Generators.

1R13

Maintenance Risk Assessments and Emergent Work Control (71111.13)

.1

Risk Assessment and Management of Risk

a.

Inspection Scope

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

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

licensee procedures prior to changes in plant configuration for maintenance activities

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

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

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

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

corrected problems related to maintenance risk assessments.

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

emergency core cooling system TS 3.0.3 entry

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

after unplanned shutdown and southern California fires

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

steam isolation valve dual indication

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

Devers offsite power out of service - delayed midloop operations

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b.

Findings

No findings of significance were identified.

1R15

Operability Evaluations (71111.15)

a.

Inspection Scope

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

emergent work documentation, deferred modifications, and standing orders to

determine if an operability evaluation was warranted for degraded components;

(2) referred to the UFSAR and design basis documents to review the technical

adequacy of licensee operability evaluations; (3) evaluated compensatory measures

associated with operability evaluations; (4) determined degraded component impact on

ENCLOSURE 2

-21-

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

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

identified and implemented appropriate corrective actions associated with degraded

components.

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

cooling flow indicators

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

eductor

October 9, 2007, Unit 3, grounded pressurizer heater

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

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

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b.

Findings

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

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

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

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

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

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

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

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

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

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

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

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

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

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

overspeed on turbine start.

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

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

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

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

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

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

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

the turbine driven AFW pump inoperable.

ENCLOSURE 2

-22-

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

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

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

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

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

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

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

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

modification was inadequate.

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

procedure to reflect the guidance found in the Temporary Modifications Control

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

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

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

environment in the AFW trench.

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

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

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

control attribute of the mitigating systems cornerstone and impacted the cornerstone

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

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

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

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

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

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

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

extent of conditions.

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

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

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

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

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

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

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

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

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

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

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

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

Modifications in the Auxiliary Feedwater Steam Supply Trench.

ENCLOSURE 2

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1R17

Permanent Plant Modifications (71111.17B)

a.

Inspection Scope

The inspectors reviewed seven permanent plant modification packages and associated

documentation, such as implementation reviews, safety evaluation applicability

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

regulatory requirements and plant procedures. The inspectors also reviewed the

procedures governing plant modifications to evaluate the effectiveness of the program

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

adversely affect the design and licensing basis of the facility.

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

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

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

packages and process.

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

identify and correct problems concerning the performance of permanent plant

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

condition reports are identified in the attachment.

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

permanent plant modifications. The inspectors completed review of seven permanent

plant modifications.

b. Findings

No findings of significance were identified.

1R19

Postmaintenance Testing (71111.19)

a.

Inspection Scope

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

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

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

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

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

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

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

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

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

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

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

corrected problems related to post maintenance testing.

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

safe closure postmaintenance test

ENCLOSURE 2

-24-

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

fail safe closure postmaintenance test

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

post weld overlay liquid penetrant postmaintenance test

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

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

following corrective maintenance

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

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b.

Findings

No findings of significance were identified.

1R20

Refueling and Other Outage Activities (71111.20)

a.

Inspection Scope

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

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

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

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

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

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

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

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

and implementation of appropriate corrective actions associated with refueling and

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

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

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

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

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

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

inspection period.

The inspectors completed two samples.

b.

Findings

No findings of significance were identified.

ENCLOSURE 2

-25-

1R22

Surveillance Testing (71111.22)

a.

Inspection Scope

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

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

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

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

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

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

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

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

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

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

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

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

implemented any needed corrective actions associated with the surveillance testing.

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

Valve 2HV-9900 stroke test

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

manual stroke test

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

time testing

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

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b.

Findings

No findings of significance were identified.

1R23

Temporary Plant Modifications (71111.23)

a.

Inspection Scope

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

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

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

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

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

the impact of the temporary modifications on permanently installed SSCs were

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

ENCLOSURE 2

-26-

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

corrective actions associated with temporary modifications.

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

Heater E614

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b.

Findings

No findings of significance was identified.

Cornerstone: Emergency Preparedness

1EP6

Drill Evaluation (71114.06)

a.

Inspection Scope

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

Performance and Emergency Response Organization Performance Indicators, the

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

deficiencies in classification, notification, and Protective Action Recommendation

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

licensee identified findings to determine whether the licensee is properly identifying

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

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

acceptance criteria.

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

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

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

subsequent tube rupture with potential unfiltered radioactive release pathway

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

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b.

Findings

No findings of significance were identified.

ENCLOSURE 2

-27-

2.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control To Radiologically Significant Areas (71121.01)

a.

Inspection Scope

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

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

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

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

procedures required by technical specifications as criteria for determining compliance.

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

radiation protection supervisors, and radiation workers. The inspector performed

independent radiation dose rate measurements and reviewed the following items:

Performance indicator events and associated documentation packages reported

by the licensee in the Occupational Radiation Safety Cornerstone

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

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

Containment Buildings

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

locations

Conformity of electronic personal dosimeter alarm set points with survey

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

electronic personnel dosimeter noticeably malfunctions or alarms

Barrier integrity and performance of engineering controls in two potential

airborne radioactivity areas

Adequacy of the licensees internal dose assessment for any actual internal

exposure greater than 50 millirem committed effective dose equivalent

Physical and programmatic controls for highly activated or contaminated

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

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

the access control program since the last inspection

Corrective action documents related to access controls

Licensee actions in cases of repetitive deficiencies or significant individual

deficiencies

Radiation exposure permit briefings and worker instructions

ENCLOSURE 2

-28-

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

job coverage, and contamination control during job performance

Dosimetry placement in high radiation work areas with significant dose rate

gradients

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

and very high radiation areas

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

areas during certain plant operations

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

areas and very high radiation areas

Radiation worker and radiation protection technician performance with respect to

radiation protection work requirements

The inspector completed 21 of the required 21 samples.

b.

Findings

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

failed to follow radiation work permit instructions.

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

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

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

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

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

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

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

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

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

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

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

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

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

implement a mechanism for communicating associated boundary walk downs in

maintenance orders.

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

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

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

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

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

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

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

ENCLOSURE 2

-29-

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

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

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

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

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

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

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

area H4a].

Enforcement. Technical Specification 5.5.1.1.a requires applicable procedures

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

permit requirement.

2OS2 Planning and Controls (71121.02)

a.

Inspection Scope

The inspector assessed licensee performance with respect to maintaining individual and

collective radiation exposures ALARA. The inspector used the requirements in 10 CFR Part 20 and the licensees procedures required by technical specifications as criteria for

determining compliance. The inspector interviewed licensee personnel and reviewed:

Site-specific ALARA procedures

Interfaces between operations, radiation protection, maintenance, maintenance

planning, scheduling and engineering groups

Integration of ALARA requirements into work procedure and radiation work permit

(or radiation exposure permit) documents

Dose rate reduction activities in work planning

Exposure tracking system

ENCLOSURE 2

-30-

Use of engineering controls to achieve dose reductions and dose reduction

benefits afforded by shielding

Workers use of the low dose waiting areas

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

a dose efficient manner

Radiation worker and radiation protection technician performance during work

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

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

since the last inspection

Resolution through the corrective action process of problems identified through

post-job reviews and post-outage ALARA report critiques

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

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

Effectiveness of self-assessment activities with respect to identifying and

addressing repetitive deficiencies or significant individual deficiencies

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

b.

Findings

No findings of significance were identified.

4.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification (71151)

a.

Inspection Scope

Cornerstone: Mitigating Systems

The inspectors sampled licensee data for the Mitigating System Performance

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

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

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

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

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

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

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

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

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

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

ENCLOSURE 2

-31-

monitored component. In addition, the inspectors interviewed licensee personnel

associated with PI data collection and evaluation.

Units 2 and 3, safety system functional failures

The inspectors completed two samples.

Cornerstone: Barrier Integrity

The inspectors sampled licensee submittals for the four performance indicators listed

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

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

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

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

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

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

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

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

surveillance test that determined RCS identified leakage. Licensee performance

indicator data were also reviewed for the following:

C

Units 2 and 3, reactor coolant system specific activity

C

Units 2 and 3, reactor coolant system leakage

The inspectors completed four samples.

Cornerstone : Occupational Radiation Safety

Occupational Exposure Control Effectiveness

The inspector reviewed licensee documents from January 1 through

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

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

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

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

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

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

interviewed licensee personnel that were accountable for collecting and evaluating the

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

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

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

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

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

Cornerstone: Public Radiation Safety

Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

ENCLOSURE 2

-32-

The inspector reviewed licensee documents from January 1 through

September 30, 2007. Licensee records reviewed included corrective action

documentation that identified occurrences for liquid or gaseous effluent releases that

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

inspector interviewed licensee personnel that were accountable for collecting and

evaluating the performance indicator data. Performance indicator definitions and

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

for each data element.

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

b.

Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

.1

Radiological Controls Review

a.

Inspection Scope

The inspector evaluated the effectiveness of the licensees problem identification and

resolution process with respect to the following inspection areas:

Access Control to Radiologically Significant Areas (Section 2OS1)

ALARA Planning and Controls (Section 2OS2)

b.

Findings

No findings of significance were identified.

.2

Routine Review of Identification and Resolution of Problems

a.

Inspection Scope

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

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

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

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

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

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

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

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

inspection procedures.

b.

Findings

No findings of significance were identified.

ENCLOSURE 2

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.3

Selected Issue Follow-up Inspection

a.

Inspection Scope

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

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

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

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

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

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

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

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

C

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

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

workarounds

Documents reviewed by the inspectors are listed in the attachment.

b.

Findings

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

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

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

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

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

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

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

August 8, 2007.

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

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

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

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

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

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

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

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

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

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

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

because of chronic problems with spurious trips.

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

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

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

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

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

ENCLOSURE 2

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

a thermal overload tripping on lower current.

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

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

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

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

room intake structure fans.

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

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

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

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

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

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

process.

Analysis. The failure of the licensee to properly scope corrective actions to prevent the

premature tripping of thermal overloads for safety-related equipment was considered a

performance deficiency. The finding was determined to be more than minor because it

was associated with the equipment performance attribute of the mitigating systems

cornerstone and it affected the cornerstone objective by challenging the availability and

capability of safety-related components. Using the Manual Chapter 0609, Significance

ENCLOSURE 2

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Determination Process, Phase 1 worksheet, the finding was determined to have very low

safety significance (Green) because it did not result in an actual loss of a system safety

function, a loss of a single train of safety equipment for greater than its technical

specification allowed outage time, and did not screen as potentially risk significant due to

seismic, flooding, or severe weather initiating events. The cause of the finding has a

crosscutting aspect in the area of problem identification and resolution associated with

the corrective action program (P.1(c)) because the licensee failed to thoroughly evaluate

the extent of condition of insufficient solder material on safety-related thermal overloads.

Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in

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

to quality, corrective actions are taken to preclude repetition. Contrary to this, from

February 6 through August 8, 2007, the licensee failed to take corrective actions to

preclude repetition of the premature tripping of thermal overloads for safety-related

equipment, a significant condition adverse to quality. This finding has been entered into

the licensee's corrective action program as AR 070800454. Due to the licensees failure

to restore compliance from previous NCV 05000361;05000362/2006005-04, within a

reasonable time after the violation was identified, this violation is being cited as a Notice

of Violation consistent with Section VI.A of the Enforcement Policy: VIO 05000361;05000362/2007005-04, Failure to Prevent Recurrence of Premature Tripping of Square

D Thermal Overloads.

.3

Semiannual Trend Review

a.

Inspection Scope

The inspectors completed a semi-annual trend review of repetitive or closely related

issues that were documented to identify trends that might indicate the existence of more

safety significant issues, specifically in the areas of procedural compliance and human

performance. The inspectors review consisted of the six month period from June 25,

2007, through December 31, 2007. When warranted, some of the samples expanded

beyond those dates to fully assess the issue. The inspectors also reviewed corrective

action program items associated with human performance improvement, and met with

representatives from the San Onofre human performance improvement team at regular

intervals. Corrective actions associated with a sample of the issues identified in the

licensee's trend report were reviewed for adequacy. Documents reviewed by the

inspectors are listed in the attachment.

b.

Findings

No findings of significance were identified. However, the inspectors noted that the

licensee continued to attempt to implement human performance initiatives to prevent

personnel errors. The licensee indicated that a stand alone performance improvement

plan would be implemented by January 31, 2008.

ENCLOSURE 2

-36-

4OA5 Other

.1

Temporary Instruction 2515/166, "Pressurized Water Reactor Containment Sump

Blockage," San Onofre Nuclear Generating Station, Unit 2

Temporary Instruction 2515/166 was performed at San Onofre Nuclear Generating

Station, Unit 2. The results of inspection phase of Temporary Instruction 2515/166 for

Unit 2 are subsequently documented in this report. Temporary Instruction 2515/166 for

both Unit 2 and Unit 3 will be closed out after the completion and verification of

modification commitments for Unit 2 containment sumps at the end of Refueling

Outage 15.

Listed below are the commitments and actions taken by the licensee:

1.

Design and procurement of replacement sump screens

Actions Taken

Engineering Change Packet ECP#040301974-11 dated Jul 17, 2006, provides for

the design changes of containment sump to address sump blockage concerns.

This engineering change packet has undergone NRC review and supplemental

responses to the NRC are to be received no later than February 29, 2008, per

letter to Nuclear Energy Institute (NEI) from NRC: Supplemental Licensee

Responses to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On

Emergency Recirculation During Design Basis Accidents At Pressurized-Water

Reactors," dated November 30, 2007. Materials for the sump screens have been

procured and are currently being installed during Refueling Outage RF15, with

modifications expected to complete at the end of the outage.

2.

Resolution of potential susceptibility of emergency core cooling system and

containment spray system pump mechanical seal to increased leakage due to

debris mix passing through the seals

Actions Taken

The licensee has completed calculations to evaluate seal leakage due to debris

ingestion. This action has undergone NRC review and supplemental responses

to the NRC are to be received no later than February 29, 2008, per letter to NEI

from NRC: Supplemental Licensee Responses to Generic Letter 2004-02,

"Potential Impact Of Debris Blockage On Emergency Recirculation During Design

Basis Accidents At Pressurized-Water Reactors," dated November 30, 2007.

3.

Resolution of potential susceptibility of ECCS and CSS pump mechanical seal

cyclone separators to debris blockage

ENCLOSURE 2

-37-

Actions Taken

The licensee has completed calculations to evaluate seal leakage due to debris

ingestion. This action has undergone NRC review and supplemental responses to

the NRC are to be received no later than February 29, 2008, per letter to NEI

from NRC: Supplemental Licensee Responses to Generic Letter 2004-02,

"Potential Impact Of Debris Blockage On Emergency Recirculation During Design

Basis Accidents At Pressurized-Water Reactors," dated November 30, 2007.

4.

Development of a reduced qualified protective coatings zone of influence (ZOI)

Actions Taken

ALION-CAL-SONGS2933-02, Revision 1 "San Onofre Units 2 and 3 GSI-191

Containment Recirculation Sump Evaluation: Debris Generation Calculation,"

documents the assumptions and methodology that the licensee applied to

determine the ZOI and debris generated for each postulated break. This

evaluation has undergone NRC review and supplemental responses to the NRC

are to be received no later than February 29, 2008, per letter to NEI from NRC:

Supplemental Licensee Responses to Generic Letter 2004-02, "Potential Impact

Of Debris Blockage On Emergency Recirculation During Design Basis Accidents

at Pressurized-Water Reactors," dated November 30, 2007.

5.

Validation of the 8 percent head loss margin adjustment factor for chemical

effects (SONGS uses Trisodium Phosphate (TSP) as a post-LOCA pH buffering

agent, and pertinent debris loads are primarily mineral wool fibrous insulation,

making NRC's Integrated Chemical Effects Test (ICET) 2 generally applicable,

but the licensee stated that chemical effects values were subject to follow-on

sump screen vendor testing, and SCE evaluations and walkdowns).

Actions Taken

Chemical effect tests were completed by Alion Science and Technology, and

directly observed by the NRC, in Warrenville, Illinois on August 17 - 18, 2006.

Open items from the NRC review are to be addressed and supplemental

responses to the NRC are to be received no later than February 29, 2008, per

letter to NEI from NRC: Supplemental Licensee Responses to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On Emergency

Recirculation During Design Basis Accidents At Pressurized-Water Reactors,"

dated November 30, 2007.

6.

Containment insulation configuration control to ensure the amounts and types of

insulation remain within acceptable debris loading design margins

Actions Taken

The licensee has removed microtherm insulation on four different piping

segments in containment. This insulation is to be replaced by reflective metal

insulation where appropriate. Mineral wool insulation on the steam generators is

ENCLOSURE 2

-38-

to be replaced with RMI during the steam generator replacement activities in

2009. These actions have undergone NRC review and supplemental responses to

the NRC are to be received no later than February 29, 2008, per letter to NEI

from NRC: Supplemental Licensee Responses to Generic Letter 2004-02,

"Potential Impact Of Debris Blockage On Emergency Recirculation During Design

Basis Accidents At Pressurized-Water Reactors" dated November 30, 2007.

7.

Replace sump screens at SONGS Unit 2 during Refueling Outage Cycle 15

Actions Taken

Work currently ongoing and expected to be completed by the end of the refueling

outage.

8.

Removal of microporous insulation on piping to be completed coincident with

sump screen replacement.

Actions Taken

Work currently ongoing and expected to be completed by the end of the refueling

outage.

9.

Modification fo steel grates at the entry to the bioshield to reduce the potential for

debris blockage and resultant hold-up of recirculating water to be completed

coincident with sump screen replacement.

Actions Taken

Work currently ongoing and expected to be completed by the end of the refueling

outage.

4OA6 Meetings, Including Exit

On November 9, 2007, the engineering inspectors presented the results of the

permanent plant modifications inspection and the evaluation of changes, tests, or

experiments inspection to Dr. R. Waldo and others who acknowledged the findings.

On November 30, 2007, the health physics inspectors presented inspection results to

Mr. J. Reilly and others who acknowledged the findings.

On December 3, 2007, the inspector discussed the inspection results of the licensed

operator annual requalification examination with Mr. B. Arbour, Training Supervisor. A

telephone exit was held with Mr. Arbour, on December 3, 2007. The licensee

acknowledged the findings presented in both the briefing and the final exit meeting.

On December 13, 2007, the inspectors presented the results of this inservice inspection

to J.T. Reilly, Vice-President Engineering and Technical Services, and other members of

licensee management. Licensee management acknowledged the inspection findings.

ENCLOSURE 2

-39-

On December 21, 2007, and on February 13, 2008, the inspectors presented the

quarterly inspection results to Mr. R. Ridenoure and others who acknowledged the

findings.

The inspectors confirmed that proprietary information was not provided or examined

during the inspection.

4OA7 Licensee-Identified Violations

The following violation of very low significance (Green) was identified by the licensee and

is a violation of NRC requirements which meets the criteria of Section VI of the

NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

Licensee Technical Specification Section 5.5.1.1.a requires applicable procedures

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

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

work permit system. Radiation Exposure Permit A081997001/200117-8 requires

workers to wear radiological protective clothing for entry into contaminated areas,

such as shoe covers and gloves. Contrary to this requirement, there were three

examples of security officers entering contaminated areas without the required

protective clothing. The first example occurred on October 9, 2007, when two

security guards entered a posted contaminated area in Unit 3, Room 411 of the

penetrations building, without the required radiological protective clothing. The

second example occurred on November 12, 2007, when a security guard entered

a posted contaminated area in Unit 2, Room 209 without the required radiological

protective clothing. The third example occurred November 13, 2007, when a

security guard entered a posted contaminated area in Unit 2, Room 209 without

the required radiological protective clothing. In all three examples, the area

postings had changed and with inattention to detail, the officers entered the areas

without the required radiological protective clothing. This issue was entered into

the licensee's corrective action program (Action Requests 071000551,

071100759, and 071100760). This finding is of very low safety significance

because it did not involve: (1) ALARA planning and controls, (2) an overexposure,

(3) a substantial potential for overexposure, or (4) an impaired ability to assess

dose.

ATTACHMENT: SUPPLEMENTAL INFORMATION

ATTACHMENT

A-1

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

D. Axline, Technical Specialist, Nuclear Regulatory Affairs

D. Breig, Manager, Engineering Standards and Excellence

B. Corbett, Manager, Health Physics

J. Hirsch, Manager, Maintenance

K. Johnson, Manager, Design Engineering

R. Ridenoure, Vice President, Nuclear Generation

L. Kelly, Engineer, Nuclear Regulatory Affairs

C. McAndrews, Manager, Nuclear Oversight and Assessment

N. Quigley, Manager, Mechanical/Nuclear Maintenance Engineering

J. Reilly, Vice President, Engineering and Technical Services

A. Scherer, Manager, Nuclear Regulatory Affairs

R. St. Onge, Manager, Maintenance and Systems Engineering

T. Vogt, Manager, Special Projects

D. Wilcockson, Manager, Plant Operations

C. Williams, Manager, Compliance

T. Yackle, Manager, Operations

O. Flores, Manager, Chemistry

J. Morales, Manager, Projects

M. Cooper, Manager, Maintenance and Systems Engineering

S. Gardner, Nuclear Engineer, Nuclear Regulatory Affairs

A. Mahindrakar, Technical Specialist/Scientist, Maintenance and Systems Engineering

J. Valsvig, Technical Specialist/Scientist, Maintenance and Systems Engineering

M. McDevitt, Senior Nuclear Engineer, Engineering and Technical Services

P. Chang, Nuclear Engineer, Maintenance Engineering

A. Matheney, Senior Nuclear Engineer, Engineering and Technical Services

M. Wade, Westinghouse Representative

M. Short, Director Nuclear Oversight and Assessment

J. Todd, Manager, Nuclear Oversight and Regulatory Affairs

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000361;05000362/2007005-04

NOV

Failure to Prevent Recurrence of Premature Tripping of

Square D Thermal Overloads (Section 4OA2.2)

ATTACHMENT

A-2

Opened and Closed

05000361;05000362/2007005-01

Failure to Properly Implement Maintenance Rule

Requirements for Emergency Diesel Generators

(Section 1R12)05000362/2007005-02

Failure to Implement Procedural Requirements for

Modificaitons in the Auxiliary Feedwater Steam Supply

Trench (Section 1R15)05000362/2007005-03

Failure to Follow a Radiation Exposure Permit Requirement

(Section 2OS1)

Closed

None

Discussed

None

LIST OF DOCUMENTS REVIEWED

In addition to the documents called out in the inspection report, the following documents were

selected and reviewed by the inspectors to accomplish the objectives and scope of the

inspection and to support any findings:

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

10 CFR 50.59 Evaluations

020701289-37

Auxiliary steam system radwaste condensate return

line rad monitor flow valve change - Fix position of

Condensate Return Valve 2/3FV-7546 and remove

2/3FIC-7546

Revision 0

050801215-08

Change to the U3C14 Core Fuel Loading Pattern

Revision 0

060101335-13

Reduction in the number of Dome Air Circulator Fans

Credited for Containment Sprayed and Unsprayed

Region Mixing.

Revision 0

060401009-06

One-time change to the testing frequency for the High

Pressure Turbine Stop and Control Valves

Revision 0

ATTACHMENT

A-3

060700747-13

Perform Calculation to evaluate the effects of air pocket

on Engineered Safety Feature pump performance.

Revision 0

060700747-18

Perform Calculation to evaluate the effects of air pocket

on Engineered Safety Feature pump performance.

Revision 1

060800698-13

Engineering design work by Bechtel to support steam

generator replacement - Remove one Containment

Hydrogen Recombiner E146 for one cycle of operation

to facilitate Steam Generator Replacement

Revision 0

060800698-44

Change to UFSAR Section 8.1, paragraph 8.1.4.3.14.B

Revision 0

10 CFR 50.59 Screenings

040400696-17

Add ECP vent line at AFW pump motor outboard

bearing housing to eliminate oil leak

09/25/2007

041100092-79

Need to Evaluate U-2 CCW Fisher Butterfly valve

concerning valve taper pin issue

050300070-05

Install Steam Trap in Auxiliary Steam Cross-tie header

050901044-40

Technical specification bases change to allow

substituting B00X for battery B007 and B008 for

temporary battery outage

11/01/2005

050901044-43

Technical specification bases change to allow

substituting B00X for battery B007 and B008 for

temporary battery outage

11/03/2005

050901044-61

Phase I of the Class 1E DC system upgrade

10/27/2005

050901044-61

Technical specification bases change to allow

substituting B00X for battery B007 and B008 for

temporary battery outage (update)

12/16/2005

050901044-82

Technical specification bases change to allow

substituting B00X for battery B007 and B008 for

temporary battery outage

03/20/2006

051000132-06

Update AOV Program Procedure to update valve IST

Procedure.

051200901-07

Installation of a flow orifice downstream of 2PCV4716

07/25/2006

060200607-18

Add DC shunts to batteries 2B007 and 2B009 for

monitoring current

06/08/2006

ATTACHMENT

A-4

060200607-51

Add DC shunts to batteries 2B007 and 2B009 for

monitoring current - Addition of an 800 Amp, 100 mV

DC shunt at the positive polarity of battery B00X

08/02/2006

060400474-04

Modify required actions in procedure SO23-5-1.7 to

require MODE 3 entry for 1-3 inoperable MSSVs per

04/10/2006

060400474-12

Modify required actions in procedure SO23-5-1.7 to

require MODE 3 entry for 1-3 inoperable MSSVs per

04/14/2006

060400474-32

Modify required actions in procedure SO23-5-1.7 to

require MODE 3 entry for 1-3 inoperable MSSVs per

07/27/2006

060400474-41

Modify required actions in procedure SO23-5-1.7 to

require MODE 3 entry for 1-3 inoperable MSSVs per

10/04/2006

060500070-14

ECP# 060500070-10: Replace 3P123 Feeder Breaker

05/052006

060500211-21

Replace vertical air tank S31319MV048

05/18/2006

060500211-38

Replace vertical air tank S31319MV048

06/16/2006

060500211-43

Replace vertical air tank S31319MV048

08/10/2006

060600089-84

Increase Thermal Overload size in breakers 2BY37,

3BY37, 3BZ33

09/18/2006

060800603-02

Replace existing R3, R4 potentiometers with a new

model in AVR for EDG.

01/24/2007

060800603-16

Replace existing R3, R4 potentiometers with a new

model in AVR for EDG.

01/24/2007

060800603-29

Replace existing R3, R4 potentiometers with a new

model in AVR for EDG.

03/07/2007

061001071-19

Use of new E4C-109 battery short circuit methodology

03/28/2007

061001842-82

Upsize Thermal Overloads to avoid Spurious Trips

11/15/2006

061100895-11

Material condition of Generator Neutral Grounding

Resistor is poor.

061101272-04

Install Lifting Eye Pad on beam to allow in-line lift

capability when changing out safety valve.

ATTACHMENT

A-5

070200876-05

Code upgrade installation for CENTS computer code

version 06100

02/26/2007

070200876-06

Code upgrade installation for TORCGEOM computer

code version 1.0.5

03/26/2007

070200876-07

Code upgrade installation for REX computer code

version 2.1.6

09/20/2007

070200876-08

Code upgrade installation for CORD computer code

version 1.3.7

09/20/2007

070700512-06

Lower the Set Point of the concerned instruments and

provide Control Room indication of actual pressure.

Calculations

E4C-112, CCN 72

Class 1E 480V MCC Protection Calculation

Revision 1

E4C-112,

ECN A46476

Class 1E 480V MCC Protection Calculation

Revision 1

E4C-112,CCN 55

Class 1E 480V MCC Protection Calculation

Revision 1

M-0012-039

ESF Pump Suction with Entrained Air after RAS

(Recirculation Actuation Signal)

Revision 0

N-4061-001

Post-Loss Of Coolant Accident Summary of Low

Populated Zones and Offsite Doses

Revision 2

N-4061-002

Post-Loss Of Coolant Accident Containment Leakage -

Control Room and Offsite Doses

Revision 1

Action Requests

050901044

060200607

060400474

060800603

061001071

Section 1R04: Equipment Alignment

Procedures

SO23-3-2.6

Shutdown Cooling System Operation

Revision 24

SD-SO23-780

Auxiliary Feedwater System

Revision 10

SD-SO23-120

6.9 kV, 4.16 kV and 480 V Electrical Distribution Systems

Revision 16

SO23-5-1.8.1

Shutdown Nuclear Safety

Revision 17

ATTACHMENT

A-6

Drawings and Calculations

SD-SO23-740

Shutdown Cooling System

Revision 17

40160A

Auxiliary Feedwater System - No. 1305"

Revision 43

40160B

Auxiliary Feedwater Steam Supply System - No. 1301"

Revision 21

40160C

Auxiliary Feedwater System Hydraulic Valves 2HV-4714

& 4731 Control Fluid System No. 1305"

Revision 7

40160X

Auxiliary Feedwater System No. 1305 and Auxiliary

Feedwater Steam Supply System No. 1301"

Revision 4

Section 1R05: Fire Protection

Procedures

2-013

Unit 2, diesel generator pre-fire plans

Revision 4

3-0345

Unit 3, diesel generator pre-fire plans

Revision 4

2-007

Unit 2, Safety Equipment Building (-)15'6"

elevation

Revision 3

UFHA 2/3-7.0-2SE

Updated Fire Hazard Analysis

May 2007

Action Requests

070901019

070901022

Section 1R08: Inservice Inspections

Procedures

Number

Title

Revision

SO23-XXVII-20.51

Visual Examination Procedure for Operability of Nuclear

Components and Supports and Conditions Relating to

Their Functional Adequacy

2

SO23-XXVII-20.48

Liquid Penetrant Examination

1

SO23-XXVII-30.13

Risk-Informed Ultrasonic Examination of Class 1

Austenitic Piping Welds

0

SO23-XXVII-30.6

Ultrasonic Examination of Austenitic Piping Welds

2

SO23-XXVII-30.9

Ultrasonic Examination of Dissimilar Metal Piping Welds

2

ATTACHMENT

A-7

PDI-UT-10

PDI Generic Procedure for the Ultrasonic Examination of

Dissimilar Metal Welds

C

9022

Reactor Coolant System Alloy 600 Material Management

Program

5

SO23-XXXIII-8.16

Reactor Coolant System Alloy 600 Inspection

5

SO23-3-2.34

Containment Access Control, Inspections and Airlocks

Operation

20

SO123-XXIV-10.1

Engineering Change Package

15

SO123-0-A4

Configuration Control

9

SO23-1-1.11.1

Plant Maintenance Procedure for Coating Service

Level 1 Application

6

SO23-XV-23.1.1

Containment Cleanliness/Loose Debris Inspection

1

SO23-V-8.17

Containment Coatings Assessment

1

QA-46

Qualification and Certification of NDE and Visual

Examination Personnel per ASME Section XI

0

WSI QAP 9.21

Liquid Penetrant Examination

1

SI-UT-126

Phased Array Ultrasonic Examination

3

T4EN51

Non-RCS Alloy 600 Boric Acid Leakage, Inspection and

Evaluation

1

T4EN52

RCS Alloy 600 Boric Acid Leakage, Inspection and

Evaluation

0

SO23-V-8.15 ISS2

Containment Boric Acid Leak Inspection

2

SO23-V-8.18

Reactor Coolant System (RCS) Leak Monitoring and

Investigation Guide

0

SO23-XV-85

Boric Acid Corrosion Control Program

1

SO23-XXXIII-8.16

Reactor Coolant System Alloy 600 Inspection

5

SO23-XXVII-3.51.9

IntraSpec UT Analysis Guidelines

5

SO23-XXVII-3.51.2

IntraSpec Eddy Current Imaging Procedure for Inspection

of Reactor Vessel Head Penetrations

5

SO23-XXVII-3.51.4

IntraSpec Ultrasonic Procedure for Inspection of Reactor

Vessel Head Penetrations, Time-of-Flight Ultrasonic,

Longitudinal Wave & Shear Wave

5

SO23-XXVII-3.51.3

IntraSpec Eddy Current Analysis Guidelines

6

ATTACHMENT

A-8

SO23-I-2.53

Containment Emergency Sump Inspection Surveillance

7

SO 123-I-11.1

Welding Filler material control

9

Corrective Action Documents

AR 070500261

AR 071101172

AR 071101173

AR 070500262

AR 070500263

AR 070500265

AR 071200384

AR 060100998

AR 060101057

AR 060100961

AR 071200751

AR 071200830

AR 060901108-89

Calculations

Number

Title

Revision

SONG-10Q-301

Weld Overlay Sizing for Pressurizer Surge Nozzle

2

Drawings

Number

Title

Revision

SONG-10Q-02

Pressurizer Surge Nozzle Weld Overlay Design and Buffer

Layer, Shts 1 and 2

1

403974

Construction Drawing Surge, SONGS, Unit 2, Shts 1 and 2

0

S2-1203-ML-229

Letdown Heat Exchanger E-602 to Line 100: UA

2TV-0223, Sht 1

12

S2-1203-ML-498

Component Cooling Water, Sht 1

0

Examination Technique Specification Sheets (ETSS)

San Onofre Nuclear Generating Station

ETSS

Qualifying EPRI ETSSs

ETSS #1

96004.1, 96005.2, 96008.1, 96012.1,

24013.1, 20511.1

ETSS #9

23514.1, .2, .3

ETSS #3

20510.1, 20511.1, 21409.1, 21410.1,

21998.1, 22401.1, 96703.1

ETSS #4

20510.1, 20511.1, 21409.1, 21410.1,

21998.1, 22401.1, 96703.1

ATTACHMENT

A-9

ETSS #5

96008.1, 96511.2

ETSS #6

96511.2, 99997.1

Welding Procedure Specifications and Corresponding Procedure Qualification Reports

WPS 08-08-T-001-Butter SS, Revision 0: PQRs 08-08-T-009, 08-08-TS-001, 8.8.6-OKG, and

08-08-TS-002

WPS 03-08-T-804-Bottom, Revision 0: PQRs A08202.3-3, 43-43-T-001, 03-03-T-803, and

A843256-52

WPS 1-GT-SM, Manual GTAW and/or SMAW of P-Number 1 CS, Revision 1: PQRs 51, 112,

and 153

Miscellaneous

Number

Title

Revision

RPA 02-0080

Quantification of Containment Latent Debris

1

ECP#04031974-74

Microtherm Insulation to RMI Change-out ECP; Unit 2

ECP#

04031974-58

Microtherm Insulation to RMI Change-out ECP; Unit 3

ECP#

04031974-12

Sump Screen Installation and Bioshield Gate

Modification ECP; Unit 2

ECP#04031974-11

Sump Screen Installation and Bioshield Gate

Modification ECP; Unit 3

Letter to NRC from SCE: NRC Generic Letter 2004-02

Response To NRC Request For Information San

Onofre Nuclear Generating Station Units 2 and 3

March 7, 2005

Letter to SCE from NRC: San Onofre Nuclear

Generating Station Units 2 and 3-Request For

Additional Information (RAI) Related to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On

Emergency Sump Recirculation At Pressurized-Water

Reactors" (TAC NOS. MC4714 and MC4715)

June 2, 2005

Letter to NRC from SCE: NRC Generic Letter 2004-02

Response To NRC Request For Additional Information

July 5, 2005

Letter to NRC from SCE: NRC Generic Letter 2004-02

San Onofre Nuclear Generating Station Units 2 and 3

September 1,

2005

ATTACHMENT

A-10

Letter to SCE from NRC: San Onofre Nuclear

Generating Station, Units 2 and 3, Request For

Additional Information RE: Response to Generic Letter 2004-02, "Potential Impact Of Debris Blockage On

Emergency Sump Recirculation At Pressurized-Water

Reactors" (TAC NOS. MC4714 and MC4715)

February 9,

2006

Letter to PWR Owners Group from NRC: Alternative

Approach for Responding to the Nuclear Regulatory

Commission Request for Additional Information Letter

RE: Generic Letter 2004-02 (TAC NOS. See

Enclosure)

March 26,

2006

Letter to PWR Owners Group from NRC: Alternative

Approach for Responding to the Nuclear Regulatory

Commission Request for Additional Information Letter

RE: Generic Letter 2004-02 (TAC NOS. See

Enclosure)

January 4,

2007

San Onofre Nuclear Generating Station Units 2 and 3-

Report on Results of Staff Audit of Corrective Actions

to Address Generic Letter 2004-02 (TAC NOS.

MC4714 and MC4715)

May 16, 2007

Letter to NEI from NRC: Plant-Specific Requests for

Extension of Time to Complete One or More

Corrective Actions for Generic Letter 2004-02,

"Potential Impact Of Debris Blockage On Emergency

Recirculation During

Design Basis Accidents At Pressurized-Water

Reactors"

November 8,

2007

Letter to NEI from NRC: Supplemental Licensee

Responses to Generic Letter 2004-02, "Potential

Impact Of Debris Blockage On Emergency

Recirculation During Design Basis Accidents At

Pressurized-Water Reactors"

November 30,

2007

ASNTCP-189-1995, ASNT Standard for Qualification

and Certification of Nondestructive Testing Personnel,

1995 Edition

Request For Relief ISI-3-25, Use of Structural Weld

Overlay and Associated Alternative Repair

Techniques

NRC Safety Evaluation for Request For Relief ISI-3-25

June 12, 2007

Weld Data Sheet, Pressurizer Surge Line Nozzle -

Weld ID DMW 02-005-031

ATTACHMENT

A-11

Welder Bead Logs for ER308L and Alloy 52M

deposition on Unit 2 Pressurizer Surge Nozzle

Steam Generator Degradation Assessment for the

Cycle 15 Refueling Outages in 2007 and 2008

November 29,

2007

EA-03-009, Issuance of Order Establishing Interim

Inspection Requirements for Reactor Pressure Vessel

Heads at Pressurized Water Reactors

February 11,

2003

EPRI Report 1010087, Materials Reliability Program:

Primary System Piping Butt Weld Inspection and

Evaluation Guidelines (MRP-139) August 2005

Certificate of Compliance dated 5/29/07 for ASME

Code Section II SFA5.9 Class ER 308/308L welding

material used on sacrificial layer on pressurizer surge

nozzle

Certificate of Compliance 06369301 for ASME Code

Section II, Part C SFA-5.14 Inconel 52M welding

material used to deposit weld overlay on pressurizer

surge nozzle

WSI Traveler No. 104532-TR-004 Pressurizer Surge

Nozzle Repair Work Steps

0

San Onofre Nuclear Generating Station Unit 3 Boric

Acid Corrosion Control Program (BACCP) Health

Report for Cycle 13: 12/29/2004 - 12/12/2006 May 8,

2007

Letter from T. G.

Hiltz (NRC) to R.

M. Rosenblum

(SCEC)

San Onofre Nuclear Generating Station Units 2 and 3

Re: Third 10-year Inservice Inspection Interval

Request ISI-3-25, Use of Structural Weld Overlays

and Associated Alternative Repair Techniques (TAC

NOS MD2579 and MD2580)

June 12, 2007

Guide 5

System Component Walkdown

1

Generic Letter 88-05

Boric Acid Corrosion of Carbon Steel Pressure

Boundary Components in PWR Plants

March 17,

1988

Information Notice

86-109,

Supplement 3

Degradation of Reactor Coolant System Boundary

Resulting from Boric Acid Corrosion

January 5,

1995

90022

Southern California Edison San Onofre Nuclear

Generating Station Units 2 and 3: Reactor Coolant

System Alloy 600 Material Management Program Plan

5

ATTACHMENT

A-12

Section 1R07A: Heat Sink Performance

SO23-I-8.94

Component Cooling Water Heat Exchanger Cleaning and

Inspection

Revision 8

Action Requests

071000587

071200968

Maintenance Orders

06040726000

Section 1R11: Licensed Operator Requalification

Procedures

Lesson Plan

2RS767

Reactor Startup (Simulator)

Revision 1

Lesson Plan

2RS768

Plant Startup - Power Ascension from Mode 2 to 20%

Power (Simulator)

Revision 1

Action Requests

071000587

Maintenance Orders

06040726000

Section 1R12: Maintenance Effectiveness (Quarterly)

Procedures

SO23-3-3.23

Diesel Generator Monthly and Semi-annual Testing

Revision 30

Action Requests

070300161

ATTACHMENT

A-13

Maintenance Orders

070300161-02

070300161-04

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Procedures

SO23-5-1.4

Plant Shutdown to Hot Standby

Revision 13

SO23-5-1.3.1

Plant Startup from Hot Standby to Minimum Load

Revision 26

Shutdown Nuclear

Safety Program

Defense in Depth Planning Sheets Unit 3 Cycle 14 Fall

Midcycle Outage

Revision 0

SO23-5-1.8.1

Shutdown Nuclear Safety

Revision 16

SO123-VIII-1

Recognition and Classification of Emergencies

Revision 26

SO123-XX-6

Operator Work Around Program

Revision 5

SO23-15-52.A

Annunciator Panel 52A - FWCS/SBCS

Revision 7

SO23-3-2.10

Main Steam Isolation Valve Operation

Revision 16

SD-SO23-110

220 kV Switchyard System

Revision 16

SSSPG-SO123-

G-10

Assessment of Offsite Capabilities Following a Natural

Disaster

Revision 0

Drawings and Calculations

SO23-507-6A-3-3

MSIV, FWIV, and FWBV Hydraulic Dump Valve

Revision M

SO23-507-6A-5-3

MSIV, FWIV, and FWBV Hydraulic Dump Valve

Revision M

40156FSO3

High Pressure Feedwater System Feedwater Isolation

Valve 3HV4051 Electro-Hydraulic Actuation System

Revision 13

40141GSO3

Main Steam System Electro-Hydraulic Valve 3HV-8204

System

Revision 15

40141G

Main Steam System Electro-Hydraulic Valve 2HV-8204

System

Revision 17

M3C14 DID #1

Barrier Map - Unit 3 Auxiliary Building (El. 50')

Revision 0

M3C14 DID #1

Barrier Map - Unit 3 Safety Equipment Building (El. 15'-

6" & 5'-3")

Revision 0

ATTACHMENT

A-14

M3C14 DID #3

Barrier Map - Train A Shutdown Cooling - Unit 3

Auxiliary Building (El. 50')

Revision 0

M3C14 DID #3

Barrier Map - Train A Shutdown Cooling - Unit 3 Safety

Equipment Building (El. 15'-6" & 5'-3")

Revision 0

M3C14 DID #3

Barrier Map - Train B Shutdown Cooling - Unit 3

Auxiliary Building (El. 50')

Revision 0

M3C14 DID #3

Barrier Map - Train B Shutdown Cooling - Unit 3 Safety

Equipment Building (El. 15'-6" & 5'-3")

Revision 0

UFSAR Fig. 8.2-1

One line Diagram - Switchyards

Revision 16

Action Requests

071000609

070500815

071100595

071201499

071000250

Section 1R15: Operability Evaluations

Procedures

SO23-2-16

Operation of Waste Water systems

Revision 20

SO23-20-4

Auxiliary Feedwater System Operation

Revision 22

Vendor Spec

Kanaline SR PVC Hose

undated

Vendor Spec

Prosser Standard-Line Submersible Dewatering Pumps

Series: 9-01000 & 9-01300"

June 2003

Vendor Spec

Prosser Standard-Line Submersible Dewatering Pumps

Series: 9-50000"

March 2001

SO23-3-3.31.6

Main Feedwater System Valve Test

Revision 7

SO23-3-3.31.4

Main Steam Valve Testing - Offline

Revision 7

SO123-XV-5.1

Temporary Modification Control

Revision 8

SO23-2-16

Use of Temporary Sump Pumps

Revision 20

SO123-XV-52

Functionality Assessments and Operability

Determinations

Revision 7

SO23-3-3.60.4

Saltwater Cooling Pump and Valve Testing

Revision 9

Drawings and Calculations

40160A

Auxiliary Feedwater System

Revision 43

ATTACHMENT

A-15

40160B

Auxiliary Feedwater Steam Supply System

Revision 21

DCP 52

Plant design package to add trench eductor to TDAFW

Revision 0

Action Requests

070500586

051200901

070500815

071100965

071000309

070500578

071000901

Section 1R17: Permanent Plant Modifications (71111.17A)

Engineering Change Packages

060400474-40

Modify required actions in procedure SO23-5-1.7 to

require MODE 3 entry for 1-3 inoperable MSSVs per

Automatic Voltage Regulator

Revision

09/27/2006

060800177-07

Replacement of Diesel Generator Temperature Switch

per SEE 000036

Revision 00

061001379-84

Install CCW Bypass Flow around the Unit 3 Letdown

Heat Exchanger

Revision 00

061001842-16

Replace Existing TOL for Breaker 2BZ17

Revision 00

061001842-46

Replace Existing TOL for Breaker 3BZ25

Drawings

S3-1023-ML-229,

Sht 1

Letdown Heat Exchanger, Line 100: Valve 3TV-0223

Revision 15

S3-1203-ML-498,

Sht 1

Component Cooling Water Line S3-1203-ML-498-4"-D-

LL1 Sys 1203

Revision 0

S3-1203-ML-228,

Sht 1

S3-1203-ML-228-8"-D-LL1, From Line 099 Valve 138 to

Letdown Heat Exchanger

Revision 13

40123BS03

Reactor Coolant Chemical & Volume Control System

No. 1208

Revision 29

Permanent Plant Modifications

020701289-37

Fix Position of Condensate Return Valve 2/3FV7546

and Remove 2/3FIC-7546

01/15/2007

040400696-17

Add ECP vent line at AFW pump motor outboard

bearing housing to eliminate oil leak

09/25/2007

ATTACHMENT

A-16

050901044-40

Technical specification bases change to allow

substituting B00X for battery B007 and B008 for

temporary battery outage

11/01/2005

051200901-07

Installation of a flow orifice downstream of 2PCV4716

07/25/2006

060500211-21

Replace vertical air tank S31319MV048

05/18/2006

060800603-29

Replace existing R3, R4 potentiometers with a new

model in AVR for EDG.

03/07/2007

061101272-04

Install Pad Eye on beam over Safety Valve 3PSV0200

08/28/2007

Procedures

SO123-XV-44

10 CFR 50.59 and 72.48 Program

Revision 8

Tech Spec Amendments

PCN 576

Request to revise Main Steam Safety Valve

Requirements and Actions (T.S. 3.7.1)

11/07/2006

Section 1R19: Postmaintenance Testing

Procedures

SO23-3-3.31.4

Main Steam Isolation Valve-Offline Testing

Revision 7

SO23-3-3.31.6

Main Feedwater System Valve Test

Revision 7

SO23-XXVII-

33.14

Procedure for the Phased Array Ultrasonic Examination of

Weld Overlaid Similar and Dissimilar Metal Welds

Revision 1

WSI 104125-TR-

004

SONGS Pressurizer Surge Nozzle Repair Work Steps

Revision 0

SO23-3-3.60.4

Saltwater Cooling Pump and Valve Testing

Revision 9

SO23-3-3.31.10

Reactor Coolant Gas Vent System Test

Revision 13

Miscellaneous

006-07

Repair/Replacement Plan for Weld Overlay Repair to

Pressurizer Surge Nozzle

Revision 0

WPS -03-08-T-804-

Bottom

Weld Procedure Specification for Inconel to Stainless

Steel

Revision 0

ATTACHMENT

A-17

WPS-08-08-T-001-

ButterSS

Weld Procedure Specification for Stainless Steel Butter

Revision 0

WPS-08-08-T-001-ButterSS Bead Log

WPS-03-08-T-804-Bottom Bead Log

Section 1R20: Refueling and Outage Activities

Procedures

SO23-5-1.4

Plant Shutdown to Hot Standby

Revision 13

SO23-5-1.5

Plant Shutdown from Hot Standby to Cold Shutdown

Revision 28

SO23-3-1.8

Draining the Reactor Coolant System

Revision 26

SO23-5-1.8

Shutdown Operations (Mode 5 and 6)

Revision 17

SO23-3-3.29

Determination of Reactor Shutdown Margin

Revision 18

SO23-3-2.6

Shutdown Cooling System Operation

Revision 24

SO23-I-3.5

Refueling Sequence

Revision 14

SO23-5-1.3

Plant Startup from Cold Shutdown to Hot Standby

Revision 30

SO23-5-1.7

Operating Instruction

Revision 35

SO23-13-15

Loss Of Shutdown Cooling

Revision 16

SO23-V-8.15

Containment Boric Acid Inspection

Revision 2

M3C14 Defense In Depth Planning Sheets

Revision 0

Action Requests

071200870

071200486

Section 1R22: Surveillance Testing

Procedures

SO23-3-3.30.8

Normal HVAC and Radiation Monitor Online Valve Test

Revision 5

SO23-3-3.30.3

Component Cooling Water Seismic Makeup Valve Test

Revision 11

SO23-3-3.30.2

Train A Saltwater Cooling Valve Test

Revision 5

SO23-3-3.60.1

High Pressure Safety Injection Pump 2MP-018 Testing

Revision 7

ATTACHMENT

A-18

SO23-3-3.60.3

Component Cooling Water Pump 2MP-024 Test

Revision 8

SO23-3-3.60

Inservice Pump Testing Program

Revision 8

Section 1R23: Temporary Plant Modifications

Procedures

ECP-07100097-3

Replace grounded pressurizer heater S31201ME616

with pressurizer heater S31201ME614"

Revision 0

Drawings and Calculations

32631

Elementary diagram reactor pressurizer backup heaters

E124"

Revision 13

32632

Elementary diagram reactor pressurizer backup heaters

E128"

Revision 27

32171

One line diagram pressurizer heaters distribution panels

Revision 16

SO23-919-2-

D58

Heater element assembly

Revision 4

Section 1EP6 Drill Evaluation

Procedures

SO123-VIII-1

Emergency plan implementing procedures

Revision 26

Emergency plan Drill 0704"

October 3, 2007

SONGS Emergency Plan

Revision 16

SO123-0-A7

Notification and Reporting of Significant Events

Revision 5

Section 2OS1: Access Controls to Radiologically Significant Areas (71121.01)

Action Request Documents

061001562, 061100484, 061101431, 070700048, 070700545, 070701137, 070701389,

070800826, 071000512, 071000551, 071000551, 071100267, 071100759, 071100760

Audits, Self-Assessments, Observations, and Surveillance Reports

Health Physics Division Self-Assessment Reports for First, Second, and Third Quarter 2007

Leader Observation Program Records from May through November 2007

SCES-006-07

ATTACHMENT

A-19

Procedures

HP-I-2

Reactor Mode Change Checklist, Revision 14

SO123-VII-20

Health Physics Program, Revision 12

SO123-VII-20.6.1

Calculation of Dose from Skin Contamination, Revision 4

SO123-VII-20.7

Monitoring Internal Radiation Exposure, Revision 6

SO123-VII-20.9

Radiological Surveys, Revision 8

SO123-VII-20.9.6

Laboratory Analysis of Health Physics Air Samples, Revision 2

SO123-VII-20.11

Access Control Program, Revision 9

SO123-VII-20.11.1

Radiological Posting, Revision 8

Radiation Exposure Permits

A0707562000/200159, A0727070026, A0727070032/200101-12, A0819970001/200117-8

Miscellaneous

Selected Radiological Surveys during initial entry to Unit 2 Containment Refueling Outage

Unit 2 Shutdown Cooling Posting Plan

Section 2OS2: ALARA Planning and Controls (71121.02)

Action Request Documents

070400180, 070401109, 070401115, 070501042, 070600855, 070800568, 071101117,

071101118, 071101120, 071101121, 071101122, 071101124

Audits, Self-Assessments, Observations, and Surveillance Reports

Health Physics Division Self-Assessment Reports for First, Second, and Third Quarter 2007

Leader Observation Program Records from May through November 2007

SCES-006-07 and SOS-007-07

Procedures

HP-I-2

Reactor Mode Change Checklist, Revision 14

SO123-VII-20 Health Physics Program, Revision 11

SO123-VII-20.4

ALARA Program, Revision 4

SO123-VII-20.4.1

ALARA Design Change Reviews, Revision 4

SO123-VII-20.10

Radiological Work Planning and Controls, Revision 10

Radiation Exposure Permits

A0727070026, A1018940021

Miscellaneous

Reactor Coolant System Cobalt-58 Clean Up Curve for Unit 3 Midcycle 14

ATTACHMENT

A-20

Unit 2 Refueling Cycle 15 ALARA Daily Current Performance for November 26 through 29, 2007

Section 4OA1: Performance Indicator Verification (71151)

Procedures

SO23-XV-24

Quarterly NRC Performance Indicator (PI) Process, Revision 5

San Onofre Nuclear Generating Station; Station

Performace Report

2nd Quarter

2007

San Onofre Nuclear Generating Station; Station

Performace Report

3rd Quarter

2007

Miscellaneous

Quarterly Radiation Doses at the Site Boundary (Effluent Releases) for 2006 and 2007

Worker exposure records for radiological controlled area entries greater than 100 millirem

Section 4OA2: Identification and Resolution of Problems

Procedures

Policy Note 14

Human Performance Strategic Plan

November 9,

2007

LIST OF ACRONYMS

AFW

auxiliary feedwater

ALARA

as low as reasonably achievable

AR

Action Request

AVR

BACC

boric acid corrision control

CAP

Corrective Action Program

CFR

Code of Federal Regulations

EDG

emergency diesel generator

EPRI

Electric Power Research Institute

LER

Licensee Event Report