Text

IR 05000369-03-005 and IR 05000370-03-005 on 09/14-12/13/2003, McGuire Nuclear Station. Non-Cited Violation Noted
	ML040130636
Person / Time
Site:	McGuire, Mcguire
Issue date:	01/12/2004
From:	Haag R; NRC/RGN-II/DRP/RPB1
To:	Gordon Peterson; Duke Energy Corp
References
	IR-03-005
	Download: ML040130636 (36)
	v • d • e

January 12, 2004

Duke Energy Corporation

ATTN: Mr. G. R. Peterson

Vice President

McGuire Nuclear Station

12700 Hagers Ferry Road

Huntersville, NC 28078-8985

SUBJECT:

MCGUIRE NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT

05000369/2003005 AND 05000370/2003005

Dear Mr. Peterson:

On December 13, 2003, the US Nuclear Regulatory Commission (NRC) completed an

inspection at your McGuire Nuclear Station. The enclosed report documents the inspection

findings which were discussed on December 18, 2003, with you and members of your staff.

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

compliance with the Commissions rules and regulations and with the conditions of your

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

interviewed personnel.

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

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

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

NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A of the

NRC Enforcement Policy. If you deny this non-cited violation, you should provide a response

with the basis for your denial, within 30 days of the date of this inspection report, to the United

States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.

20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of

Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001;

and the NRC Resident Inspector at the McGuire facility.

In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter, its

enclosure, and your response (if any) will be available electronically for public inspection in the

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

2

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

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

Sincerely,

/RA/

Robert C. Haag, Chief,

Reactor Projects Branch 1

Division of Reactor Projects

Docket Nos. 50-369, 50-370

License Nos. NPF-9, NPF-17

Enclosure: NRC Integrated Inspection Report 05000369/2003005 and 05000370/2003005,

w/Attachment - Supplemental Information

cc w/encl:

C. J. Thomas

Regulatory Compliance Manager (MNS)

Duke Energy Corporation

Electronic Mail Distribution

M. T. Cash, Manager

Nuclear Regulatory Licensing

Duke Energy Corporation

526 S. Church Street

Charlotte, NC 28201-0006

Lisa Vaughan

Legal department (PB05E)

Duke Energy Corporation

422 South Church Street

Charlotte, NC 28242

Anne Cottingham

Winston and Strawn

Electronic Mail Distribution

Beverly Hall, Acting Director

Division of Radiation Protection

N. C. Department of Environmental

Health & Natural Resources

Electronic Mail Distribution

County Manager of Mecklenburg

County720 East Fourth Street

Charlotte, NC 28202

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Assistant Attorney General

N. C. Department of Justice

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Distribution w/encl:

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RIDSNRRDIPMLIPB

PUBLIC

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UBLIC DOCUMENT (circle one): YES NO

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SIGNATURE

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NAME

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Enclosure

U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos:

50-369, 50-370

License Nos:

NPF-9, NPF-17

Report Nos:

05000369/2003005 and 05000370/2003005

Licensee:

Duke Energy Corporation

Facility:

McGuire Nuclear Station, Units 1 and 2

Location:

12700 Hagers Ferry Road

Huntersville, NC 28078

Dates:

September 14 - December 13, 2003

Inspectors:

J. Brady, Senior Resident Inspector

S. Walker, Resident Inspector

M. Morgan, Senior Resident Inspector - North Anna (Sections

1R12, 1R15, 1R19, and 1R20)

S. Shaeffer, Senior Project Engineer (Sections 1R01, 1R04,

1R05, 1R13, 1R15, 1R19, and 1R20)

S. Vias, Senior Reactor Inspector (Section 4OA5.2)

D. Jones, Resident Inspector - Robinson (Sections 1R20 and

1R22)

J. Lenahan, Senior Reactor Inspector (Section 1R08)

J. Fuller, Reactor Inspector (Section 1R08)

R. Carroll, Senior Project Engineer (Sections 1R12 and 4OA1)

P. Fillion, Reactor Inspector (Section 4OA5.1)

Approved by:

Robert C. Haag

Reactor Projects Branch 1

Division of Reactor Projects

SUMMARY OF FINDINGS

IR05000369/2003-005, IR05000370/2003-005; 09/14/2003 - 12/13/2003; McGuire Nuclear

Station, Units 1 and 2; Maintenance Risk Assessment and Emergent Work Evaluation

The report covered a three month period of inspection by resident inspectors and announced

inspections by four regional engineering inspectors and two senior project engineers. One

Green non-cited violation (NCV) was identified. The significance of most findings is indicated

by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination

Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a

severity level after NRC management review. The NRC's program for overseeing the safe

operation of commercial nuclear power reactors is described in NUREG-1649, Reactor

Oversight Process, Revision 3, dated July 2000.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green. A non-cited violation (NCV) was identified by the inspectors for failure to

perform an adequate risk assessment as required by 10 CFR 50.65(a)(4) when the 1B

motor-driven auxiliary feedwater pump containment isolation valve for the 1D steam

generator (1CA42B) was closed to perform maintenance on October 14, 2003 (Section

1R13).

This finding was considered to be more than minor because the inadequate risk

assessment resulted in the assignment of an incorrect risk action level (color) for this

maintenance activity. This finding was considered to be of very low safety significance

because had the error not occurred the only additional action required would have been

management awareness of the additional risk associated with the activity.

B. Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status:

Unit 1 operated at approximately 100 percent rated thermal power (RTP) during the inspection

period.

Unit 2 began the inspection period shutdown in a refueling outage. Unit 2 was taken critical on

October 5, went on-line October 6, and reached 100 percent power on October 11. The unit

remained at approximately 100 percent RTP for the rest of the period.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01

Adverse Weather Protection

a.

Inspection Scope

The inspectors reviewed the licensees implementation of adverse weather preparation

in regard to forecasted adverse weather associated with hurricane Isabel from

September 17 to 18, 2003. The inspectors verified the licensee implemented proper

pre-established measures for forecasted high wind conditions. The inspectors

performed walkdowns of the outside plant areas and roofs of accessible safety-related

structures. Temporary outage structures were verified to be either tied down or in

process of being removed. The inspectors also reviewed the licensees outage activities

to assess whether key activities associated with components utilized during loss of

offsite power events, such as the emergency diesel generators (EDGs), were being

monitored to maximize their availability during the adverse weather conditions.

When a tornado warning was predicted for the site on November 19, 2003, the

inspectors reviewed actions taken by the licensee in accordance with procedure

RP/0/A/5700/006, Natural Disasters, prior to the onset of that weather, to ensure that

the adverse weather conditions would neither initiate a plant event nor prevent any

system, structure, or component (SSC) from performing its design function.

After the licensee completed preparations for seasonal low temperature, the inspectors

walked down the auxiliary feedwater (CA) system and the fueling water storage tank

(FWST). This equipment was selected because their safety related functions could be

affected by adverse weather (freezing conditions). The inspectors observed plant

conditions and evaluated those conditions using criteria documented in procedure

IP/0/B/3250/059, Preventive Maintenance and Operational Check of Freeze Protection.

The inspectors also reviewed the following Problem Investigation Process (PIPs)

documents associated with this area to verify that the licensee identified and

implemented appropriate corrective actions.

2

PIPs

M-02-05786, NRC Audit of Freeze Protection Found Discrepancies in Monthly

and Annual Heat Trace Procedures

M-03-00352, FWST Level Channel Failed Due to Freezing

M-03-00491, Operator Workarounds Due to FWST Level Channel Freezing

M-03-01580, FW System Requires A(1) Maintenance Status

b.

Findings

No findings of significance were identified.

1R04

Equipment Alignment

a.

Inspection Scope

Partial System Walkdowns

During this inspection period, the inspectors performed the following three partial system

walkdowns, when, as applicable, the indicated SSCs were out of service for

maintenance and testing:

Unit 2 Spent Fuel Pool Cooling with the core fully unloaded in the spent fuel pool

Unit 1A Diesel Generator with 1B Diesel Generator out of service on October 14

Unit 1 train A Residual Heat Removal with train B out of service on November 12

To evaluate the operability of the selected trains or systems under these conditions, the

inspectors verified correct valve and power alignments by comparing observed positions

of valves, switches, and electrical power breakers to the procedures and drawings listed

in the Attachment to this report.

Complete System Walkdown

The inspectors conducted a detailed review of the alignment and condition of the

Residual Heat Removal (ND) system. To determine the proper system alignment, the

inspectors reviewed the procedures, drawings, and Updated Final Safety Analysis

Report (UFSAR) sections listed in the Attachment to this report. In addition, significant

events data in the industry was reviewed to ascertain any similarities to McGuire SSCs.

The inspectors walked down the system, to verify that the existing alignment of the

system was correct. Items reviewed during the walkdown included the following:

Valves are correctly positioned and do not exhibit leakage that would impact the

function(s) of any given valve.

Electrical power is available as required.

Major system components are correctly labeled, lubricated, cooled, ventilated,

etc.

Hangers and supports are correctly installed and functional.

Essential support systems are operational.

Ancillary equipment or debris does not interfere with system performance.

3

Tagging clearances are appropriate.

Valves are locked as required by the licensees locked valve program.

The inspectors reviewed the documents listed in the Attachment to this report, to verify

that the ability of the system to perform its function(s) would not be affected by

outstanding design issues, temporary modifications, operator workarounds, adverse

conditions, and other system-related issues. In addition the inspectors also reviewed

the associated PIPs listed in the attachment to this report to verify that the licensee

identified and implemented appropriate corrective actions.

b.

Findings

No findings of significance were identified.

1R05

Fire Protection

a.

Inspection Scope

For the six areas identified below , the inspectors reviewed the licensees control of

transient combustible material and ignition sources, fire detection and suppression

capabilities, fire barriers, and any related compensatory measures, to verify that those

items were consistent with UFSAR Section 9.5.1, Fire Protection System, and Design

Basis Specification for Fire Protection, MCS-1465.00-00-0008. The inspectors walked

down accessible portions of each area and reviewed results from related surveillance

tests, as well as reviewed the associated pre-fire plan strategy, to verify that conditions

in these areas were consistent with descriptions of the areas in the Design Basis

Specification. Documents reviewed during this inspection are listed in the Attachment to

this report.

The inspected areas included:

Portions of the Unit 2 containment structure during No Mode work activities (fire

area containment)

Unit 2 safety-related switchgear rooms (fire area 18 )

Main control room (fire area 24)

Unit 2 motor-driven CA pump room (fire area 3)

Unit 2 turbine-driven CA pump room (fire area 3A)

120 volt vital AC instrument and electrical area (fire area 13)

b.

Findings

No findings of significance were identified.

4

1R06

Flood Protection Measures

a.

Inspection Scope

External Flooding

The inspectors assessed the licensees flooding mitigation plan and equipment

maintenance program to determine if they were risk informed and consistent with design

requirements. This review entailed: (1) potential flooding affects from probable

maximum flooding on the Auxiliary Building (AB); (2) potential flooding affects of cable

trenches, cable pits, and manholes; (3) potential failure of the Auxiliary Feedwater

Storage Tanks (CAST) and flooding of the Turbine Building, Diesel Generator Area, and

Yard. The inspectors reviewed the operator actions credited in the analysis to verify that

the desired results could be achieved using the plant procedure listed in the Attachment

to this report.

In addition, the inspectors walked down accessible manholes or reviewed digital

photographs taken during licensee inspections of manholes that contain safety-related

cables that are subject to flooding. This was to verify that cables and associated

support equipment described in UFSAR Sections 2.4.10, Flooding Protection

Requirements, and 8.3.1.2.37, Underground Raceway Design, were not damaged by

submergence and would perform their intended function.

Internal Flooding

The inspectors walked down the cable spreading rooms for both units and reviewed

operating experience to verify safe shutdown equipment in lower elevations would not

be affected by potential leaks from cracks in the floor. In addition, the inspectors

assessed the licensees mitigating actions for a service water (RN) line break in the CA

pump room to verify that the area configuration, features, and equipment functions were

consistent with the descriptions and assumptions used in UFSAR section 3.6.A.6,

Flooding Analysis, and in the supporting basis documents listed in the Attachment to

this report. Maintenance and testing records were examined to ensure necessary

instrumentation and equipment was available and reliable and within Technical

Specifications (TS) requirements where applicable. The inspectors reviewed the

operator actions credited in the analysis, to verify that the desired results could be

achieved using the plant procedure listed in the Attachment.

b.

Findings

No findings of significance were identified.

5

1R07

Heat Sink Performance

a.

Inspection Scope

Biennial Inspection

For the three RN cooled heat exchangers identified below, the inspectors reviewed the

documents listed in the Attachment to this report to verify that testing,

inspection/maintenance, or monitoring of biotic fouling controls were adequate to ensure

proper heat transfer. The inspectors reviewed the heat exchanger test and inspection

records to verify that testing and inspection methods were as described in the licensees

response to Generic Letter 89-13, Service Water System Problems Affecting Safety

Related Equipment. The inspectors verified that test/inspection results were trended,

that degrading trends were identified in the corrective action program, and that

corrective actions were taken to restore acceptable performance when trends were

identified. The inspectors reviewed the design documents listed in the Attachment to

this report to verify that the actual heat exchanger condition related to tube plugging was

within the bounds of the design documents. The inspectors determined whether the

assumed design temperatures, flow rates, and heat transfer factors were being verified

through testing and inspection, and whether current performance met the design.

Unit 2 component cooling water heat exchangers (RN on tube side)

Unit 2 diesel generator engine cooling water heat exchangers (RN on tube side)

Unit 2 containment spray heat exchangers (RN on shell side)

The inspectors reviewed the performance of the ultimate heat sink and sub-components

by reviewing their availability. The inspectors review of the ultimate heat sink involved

review of service water pond dam inspection records and performance of a walkdown,

review of main dam inspection records, and assessment of pump and valve

performance with the licensee system and component engineers to verify that the heat

sink and components were available and accessible to perform their heat sink function.

The inspectors reviewed PIPs for the last two years associated with RN to determine

whether any specific trends existed that were not being acted on by the licensee. For

the PIPs listed in the Attachment to this report, the inspector reviewed corrective actions

to determine if they were adequate and to determine if the problems had recurred.

b.

Findings

No findings of significance were identified.

1R08

Inservice Inspection Activities

.1

Inservice Inspection (ISI)

a.

Inspection Scope

The inspectors observed in-process Unit 2 ISI work activities and reviewed selected ISI

records. The observations and records were compared to the TS and ASME Boiler and

Pressure Vessel Code,Section XI, 1989 Edition, no Addenda, to verify compliance. In

6

addition, nondestructive examination (NDE) procedures for the below listed ISI

examination activities were reviewed. The licensee did not conduct examination of

steam generator U-tubes during the current outage. Examination results with

recordable indications and pressure boundary welding activities were not available for

review. Qualification and certification records for examiners, and equipment for selected

examination activities were reviewed. In addition, a sample of ISI issues in the

licensees corrective action program were reviewed for adequacy. The following Unit 2

ISI activities were reviewed:

Liquid Penetrant (PT) exams of weld numbers 2ND2FW16-21 and 2ND2F-367

on the 12 inch diameter residual heat removal piping located in the elevation 716

auxiliary building pipe chase.

Ultrasonic Examination (UT) of weld numbers 2ND2FW16-21 and 2ND2FW16-

22 on the 12-inch diameter residual heat removal piping located in the elevation

716 auxiliary building pipe chase. Witnessed calibration of equipment for

examination of dissimilar metal welds.

Radiographic films (RT) for weld numbers 2RHR-2A-2-3 & 2RHR-2A-3-4.

Work record for repair/replacement of three pipe supports.

Results of visual inspections performed on 11 pipe supports.

b.

Findings

No findings of significance were identified.

.2

Containment Vessel Inspection

a.

Inspection Scope

The inspectors examined interior and exterior sections of the steel containment vessel

(SCV) and reviewed selected records. The observations and records were compared to

the TS, ASME Boiler and Pressure Vessel Code, Article IWE of Section XI, 1992 Edition

and 1992 Addenda, as modified by 10 CFR 50.55a(b)(2)(vi).

The inspectors reviewed the licensees ISI procedures for containment inspection to

verify the procedures complied with the above listed requirements and specified

acceptance criteria. The inspectors examined the accessible interior surfaces of the

SCV in the pipe chase area (elevation 725) and at elevation 752 between azimuths 105

to 122 degrees in the seal table area, and the exterior surfaces of the SCV between

elevations 725 and 735 between azimuths 349 to 180 degrees. The inspectors also

reviewed records documenting visual inspection of the SCV and moisture barriers to

verify that the ISI activities were conducted in accordance with program requirements

and the acceptance criteria specified in the licensees procedures. The inspectors also

reviewed records documenting results of UT measurements to determine thickness of

the SCV in February,1999 and during the September 2003 outage to satisfy applicable

requirements of the TS and ASME Section XI.

7

b.

Findings

No findings of significance were identified.

1R11

Licensed Operator Requalification

a.

Inspection Scope

On October 22, the inspectors observed licensed-operators during requalification

simulator training for shift C, to verify that operator performance was consistent with

expected operator performance, as described in Exercise Guide OP-MC-SRT-26 and

27. This training tested the operators ability to perform abnormal and emergency

procedures dealing with load rejection, rod control malfunctions, reactor trip, safety

injection, grid disturbances, loss of electrical power, and safety injection termination.

The inspectors focused on clarity and formality of communication, use of procedures,

alarm response, control board manipulations, group dynamics and supervisory

oversight.

The inspectors observed the post-exercise critique, to verify that the licensee identified

deficiencies and discrepancies that occurred during the simulator training.

b.

Findings

No findings of significance were identified.

1R12

Maintenance Effectiveness

a.

Inspection Scope

The inspectors reviewed the four degraded SSC/function performance problems or

conditions listed below, to verify the licensees appropriate handling of these

performance problems or conditions in accordance with 10CFR50, Appendix B, Criterion

XVI, Corrective Action, and 10CFR50.65, Maintenance Rule.

Erratic steam generator level control/feedwater control

Maintenance on main steam supply to auxiliary equipment valve actuator 2SA-49

actuator resulted in additional damage to mechanical yoke stop and instrument

tubing (PIP M-03-4726)

Repetitive failure of standby shutdown facility (SSF) steam generator 1C level

indication

Lightning induced damage/loss of SSF battery charger SDSP-2

The inspectors focused on the following:

Appropriate work practices

Identifying and addressing common cause failures

Scoping in accordance with 10 CFR 50.65(b)

Characterizing reliability issues (performance)

Charging equipment unavailability (performance)

8

Trending key parameters (condition monitoring)

10 CFR 50,65(a)(1) or (a)(2) classification and reclassification, and

Appropriateness of performance criteria for SSCs/functions classified (a)(2)

and/or appropriateness and adequacy of goals and corrective actions for

SSCs/functions classified (a)(1).

b.

Findings

No findings of significance were identified.

1R13

Maintenance Risk Assessments and Emergent Work Evaluation

a.

Inspection Scope

The inspectors reviewed the licensees risk assessments and the risk management

actions used to manage risk for the plant configurations associated with the six activities

listed below. The inspectors assessed whether the licensee performed adequate risk

assessments, and implemented appropriate risk management actions when required by

10CFR50.65(a)(4). For emergent work, the inspectors also verified that any increase in

risk was promptly assessed, and that appropriate risk management actions were

promptly implemented. The inspectors also reviewed associated PIP M-03-5178,

Unrecognized yellow risk condition entered due to valve 1KC-394A going closed, to

verify that the licensee identified and implemented appropriate corrective actions:

Emergent work activities associated with Work Order (WO) 98620247, failure of

containment spray (NS) valve 1NS12B limit switch (add on pack set up)

Emergent work activities on October 6, which involved: RN water system

alignment changes to reduce 1B reactor coolant (NC) pump stator temperature

and 2A component cooling (KC) heat exchanger service water side differential

pressure increase; a wrong unit human error for mis-positioning of a Unit 1

service water valve; and the effects on 1A diesel generator operability from the

special service water alignment for the KC heat exchanger.

Scheduled work activities on Unit 1 for October 14 involving maintenance on the

1B diesel generator and maintenance on the auxiliary feedwater containment

isolation valve for the 1D steam generator (1CA42B)

Scheduled work activities on Unit 1 for the week of October 20, including

Craighead off-site power line switchyard work and emergent work on the 1A NC

pump thermal barrier component cooling water outlet isolation valve (1KC-394).

Scheduled work activities for November 13, which included 2B CA pump testing

and emergent work for a super flush of the side of the A train control room

ventilation chiller. The super flush made the Unit 1 RN system train A

inoperable, but available, and had interactions with Unit 2 that caused the

licensee to delay the Unit 2 auxiliary feedwater testing.

9

Scheduled work activities for November 19 which included work on the Unit 1

fuel handling building train B exhaust fan motor, 1A CA pump slave start test, 1A

charging pump oil gauge replacement and calibration, and 7300 protection

cabinet 2 testing. An emergent tornado warning resulted in risk management

actions being taken to delay some of the planned work.

b.

Findings

Introduction: A Green non-cited violation (NCV) was identified for failure to perform an

adequate risk assessment when the 1B motor-driven auxiliary feedwater pump

containment isolation valve for the 1D steam generator (1CA42B) was closed to perform

maintenance.

Description: The inspectors discovered, on October 14, that the licensee failed to

adequately evaluate the risk of isolating the auxiliary feedwater supply to the 1D steam

generator from the 1B motor-driven auxiliary feedwater pump. The valve was closed

and power removed on October 14, at 4:23 a.m., and was declared operable after

maintenance at 5:42 a.m., on October 15. The risk assessment assumed that the flow

path to the 1D steam generator through valve 1CA42B was functional for the entire

period of maintenance. Consequently, the risk assessment under estimated the risk

and resulted in a green code for this activity instead of a yellow code.

Analysis: Operator logs indicated that during the time valve 1CA42B was unavailable,

the 1B emergency diesel generator was also unavailable for planned maintenance on

October 14 from 4:15 a.m. until 7:01 p.m. It was returned to a functional status at 4:24

p.m. The 1B EDG activity was coded as yellow. Consequently, the coding of 1CA42B

as yellow would have added a second yellow until the EDG became available, and

would have been the only yellow until the valve was returned to functional. This issue

was considered to be more than minor in the mitigating system cornerstone because the

inadequate risk assessment resulted in the identification of an incorrect risk action level

(color). This issue was considered to be of very low safety significance because had the

error not occurred the only additional action required would have been management

awareness of the additional risk associated with the activity.

Enforcement: 10 CFR 50.65(a)(4) requires that before performing maintenance

activities, the licensee shall assess and manage the increase in risk that may result from

the proposed maintenance activities. Contrary to the above, on October 14, the

licensee failed to properly assess the increase in risk from isolating the auxiliary

feedwater supply to the 1D steam generator from the 1B motor-driven auxiliary

feedwater pump in that the licensees risk assessment assumed that the function was

available when it was not. Consequently, the risk assessment was inaccurate. The

failure to have an adequate risk assessment as required by 10 CFR 50.65(a)(4) is being

treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy and is

identified as NCV 05000369/2003005-01: Inadequate Risk Assessment For 1CA42B

Out-of-service. This issue is in the licensees corrective action program as PIP M-03-

5115.

10

1R14

Personnel Performance During Nonroutine Plant Evolutions

a.

Inspection Scope

During the non-routine evolutions associated with Unit 2 plant startup from refueling

outage, the inspectors observed plant instruments and operator performance to verify

that operator performance was in accordance with procedure OP/2/A/6100/003,

Controlling Procedure for Unit Operations, and related training.

b.

Findings

No findings of significance were identified.

1R15

Operability Evaluations

a.

Inspection Scope

The inspectors reviewed the five operability determinations associated with the PIPs

listed below. The inspectors assessed the accuracy of the evaluations, the use and

control of any necessary compensatory measures, and compliance with the TS. The

inspectors verified that the operability determinations were made as specified by

Nuclear System Directive (NSD) 203, Operability. The inspectors compared the

arguments made in the determination to the requirements in TS, the UFSAR, and

associated design-basis documents, to verify that operability was properly justified and

the subject component or system remained available, such that no unrecognized

increase in risk occurred.

M-03-2668

Evaluate settlement of the 1A EDG exhaust missile barrier

M-03-4260

Unit 2 in mast sipping failed to identify suspect fuel defect

M-03-2861

Unanalyzed thermal transient on Unit 2 pressurizer power

operated relief valve (PORV) piping and components

M-03-5405

Low magnitude pressure surge occurred when valve 2RN-162B

was closed during service water flush of supply lines to the

auxiliary feedwater system (also PIP M-01-01573, previous similar

occurrence)

M-03-5055

Unit 2 pressurizer PORV piping temperatures lower than assumed

in previous operability evaluation

b.

Findings

No findings of significance were identified.

11

1R16

Operator Work-Arounds

a.

Inspection Scope

The inspectors reviewed the cumulative effects of the operator work-arounds listed in

the attachment to this report, to verify that those effects would not increase an initiating

event frequency, affect multiple mitigating systems, or affect the ability of operators to

respond in a correct and timely manner to plant transients and accidents.

b.

Findings

No findings of significance were identified.

1R19

Post-Maintenance Testing

a.

Inspection Scope

For the post-maintenance tests listed below, the inspectors witnessed the test and/or

reviewed the test data, to verify that test results adequately demonstrated restoration of

the affected safety function(s) described in the UFSAR and TS. The tests included the

following:

PT/2/A/4350/002A, Diesel Generator 2A Operability Test (outage maintenance)

PT/2/A/4350/002B, Diesel Generator 2B Operability Test (outage maintenance)

PT/2/A/4401/013, KC to NC pump Flow Balance Test (repair of various KC

valves)

PT/2/A/4403/005A, RN Train 2A Head Curve Verification (repair of various RN

components and 2A pump bearing repair)

OP/2/A/6200/009, Adjustment of Accumulator Pressures (reseating of C cold leg

accumulator check valve 2NI-81)

PT/2/A/4204/005B, ND Train B Valve Stroke Timing - Shutdown (replacement of

2ND-15B actuator)

b.

Findings

No findings of significance were identified.

1R20

Refueling and Outage Activities

a.

Inspection Scope

The inspectors evaluated licensee outage activities to verify that the licensee considered

risk in revising outage schedules, adhered to administrative risk reduction

methodologies they developed to control plant configuration, adhered to operating

license and TS requirements that maintained defense-in-depth, and developed

mitigation strategies for losses of the key safety functions identified below:

Decay heat removal

Inventory control

12

Power availability

Reactivity control

Containment

The inspectors observed the items or activities described below, to verify that the

licensee maintained defense-in-depth commensurate with the outage risk control plan

for key safety functions and applicable TS when taking equipment out of service. The

inspectors reviewed the licensees responses to emergent work and unexpected

conditions to verify that resulting configuration changes were controlled in accordance

with the outage risk control plan, and to verify that control room operators were kept

cognizant of plant configuration.

Clearance Activities

Reactor Coolant System (RCS) Instrumentation

Electrical Power

Decay Heat Removal (DHR)

Spent Fuel Pool Cooling

Inventory Control

Reactivity Control

Containment Closure

The inspectors also observed fuel handling operations (insertion) and other ongoing

activities including Control Rod Latching, to verify that those operations and activities

were being performed in accordance with TS and approved procedures. Additionally,

the inspectors observed refueling activities to verify that the location of the fuel

assemblies was tracked, including new fuel, from core offload through core reload.

Prior to mode changes and on a sampling basis, the inspectors reviewed system lineups

and/or control board indications to verify that TS, license conditions, and other

requirements, commitments, and administrative procedure prerequisites for mode

changes were met prior to changing modes or plant configurations. Also, the inspectors

periodically reviewed RCS boundary leakage data, and observed the setting of

containment integrity, to verify that the RCS and containment boundaries were in place

and had integrity when necessary. Prior to reactor startup, the inspectors walked down

containment to verify that debris has not been left which could affect performance of the

containment sumps. The inspectors reviewed reactor startup and unit synchronization

to the grid to verify procedure compliance and that systems performed as designed.

The inspectors reviewed reactor physics testing results to verify that core operating limit

parameters were consistent with the design.

Periodically, the inspectors reviewed the items that had been entered into the licensees

corrective action program, to verify that the licensee had identified problems related to

outage activities at an appropriate threshold and had entered them into the corrective

action program. For the significant problems documented in the corrective action

program and listed on the Attachment to this report, the inspectors reviewed the results

of the licensees investigations to verify that the licensee had determined the root cause

13

and implemented appropriate corrective actions, as required by 10CFR50, Appendix B,

Criterion XVI, Corrective Action.

b.

Findings

No findings of significance were identified.

1R22

Surveillance Testing

a.

Inspection Scope

For the surveillance tests identified below, the inspectors witnessed testing and/or

reviewed the test data, to verify that the systems, structures, and components involved

in these tests satisfied the requirements described in the Technical Specifications, the

UFSAR, and applicable licensee procedures, and that the tests demonstrated that the

SSCs were capable of performing their intended safety functions.

PT/2/A/4350/004A, 2A D/G [Diesel Generator] Periodic and Load Sequencer

Test

PT/2/A4200/009 A, Engineered Safety Features Actuation Periodic Test Train A,

on September 26

PT/2/A4200/009 B, Engineered Safety Features Actuation Periodic Test Train B,

on September 27

SM/0/A/8510/006, Ice Condenser Intermediate Deck Doors Inspection and

Corrective Maintenance

PT/0/A/4200/032, Periodic Inspection of Ice Condenser Lower Inlet Doors

PT/2/A/4403/001A, 2A RN Pump Performance Test*

PT/2/A/4252/001A, 2A CA Pump Performance Test*

PT/2/A/4200/001 N, VP Valve Leak Rate Test**

This procedure included inservice testing requirements.

- This procedure included testing of a large containment isolation valve.

The inspectors reviewed associated PIP M-03-2880, Cylinder 1 on Unit 2 A EDG

exhibited low exhaust temperature for one minute during 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run, to verify that the

licensee identified and implemented appropriate corrective actions.

b.

Findings

No findings of significance were identified.

1R23

Temporary Plant Modifications

a.

Inspection Scope

The inspectors reviewed the temporary modifications described in the McGuire

Temporary Modifications (MGTM) listed below, to verify that the modifications did not

affect the safety functions of important safety systems, and to verify that the

modifications satisfied the requirements of 10CFR50, Appendix B, Criterion III, Design

Control.

14

MGTM-0302, Leak repair pipe cap for 2NI-465, unit 2 NV to 2B NC cold leg high

point vent valve

MGTM-0306, Bypass FWST trench sump pump high level cutoff switch until

new switch arrives.

The inspectors also reviewed tag outs open on December 10, 2003, to verify that tag

outs were not being used to implement temporary modifications.

b.

Findings

No findings of significance were identified.

4.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

a.

Inspection Scope

For the performance indicators (PIs) listed below, the inspectors sampled licensee PI

data for the period from July 2002 through September 2003. To verify the accuracy of

the PI data reported for both units during that period, the inspectors compared the

licensees basis in reporting each data element to the PI definitions and guidance

contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Rev. 2.

Mitigating Systems Cornerstone

Safety System Unavailability, High Pressure Safety Injection

The inspectors reviewed Licensee Event Reports, records of inoperable equipment, and

Maintenance Rule records, to verify that the licensee had adequately accounted for

unavailability hours that the subject systems had experienced during the previous four

quarters. The inspectors also reviewed the number of hours those systems were

required to be available and the licensees basis for identifying unavailability hours. In

addition, the inspectors interviewed licensee personnel associated with the PI data

collection, evaluation, and distribution.

Integrity Cornerstone

Reactor Coolant System Specific Activity

The inspectors observed licensee sampling and analysis of reactor coolant system

samples, and compared the licensee-reported performance indicator data with records

developed by the licensee while analyzing previous samples. The inspectors also

reviewed the following PIPs associated with this area to verify that the licensee identified

and implemented appropriate corrective actions:

M-03-05536, 3 Primary Chemistry Samples Analyzed With Incorrect Sample

Times, dated 11/12/03

M-03-05686, Chemistry HPRC Procedure Benchmarking Project, dated 11/12/03

15

b.

Findings

No findings of significance were identified

4OA2 Problem Identification and Resolution

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

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

issues for follow-up, the inspectors performed a daily screening of items entered into the

licensees corrective action program. This review was accomplished by reviewing hard

copies of each condition report, attending daily screening meetings, and accessing the

licensees computerized database.

4OA5 Other Activities

.1

(Closed) Unresolved Item (URI) 50-369, 370/2003007001: Fire Suppression System for

Dedicated Shutdown Areas Not in Accordance with 10 CFR 50, Appendix R, Section

III.G.3

This URI was opened pending evaluation of whether a backfit was warranted to require

that the existing partial suppression capability be expanded to whole area suppression.

Though the URI writeup describes the partial suppression system in Fire Area 4, the

report alludes to other III.G.3 areas with similar partial suppression.

The inspector used the significance determination process to determine the change in

risk that would result from expanding the existing suppression system from partial

coverage to area wide coverage. This analysis indicated no significant difference in risk

between the normal suppression and degraded suppression cases. Hence, the

inspector concluded that backfitting to provide area wide suppression was not

warranted. This analysis considered the worst case of post-fire shutdown with only the

standby shutdown system available. Both the transient worksheet and the loss of

nuclear service water worksheets were evaluated. Insights gained from this analysis,

which focused on Fire Area 4, led to the conclusion that the same result would be

obtained for any auxiliary building III.G.3 area at McGuire. This is primarily due to the

small difference in initiating event likelihood between the normal suppression and

degraded suppression cases and the relatively low likelihood values. There were only

three other III.G.3 areas. Two were the cable spreading rooms which had misty fog type

suppression systems. The other was the control room, which is a generic exception to

the requirement to have a fixed suppression system.

.2

Reactor Pressure Vessel Lower Head Penetration Nozzle Inspection

a.

Inspection Scope (TI 2515/152)

The inspectors observed activities associated with the inspection of the Unit 2 reactor

vessel lower head penetrations in response to NRC Bulletin 2003-02. The guidelines for

the inspection are provided in NRC temporary instruction (TI) procedure 2515/152,

Reactor Pressure Vessel (RPV) Lower Head Penetration Nozzle Inspection (NRC

Bulletin 2003-02).

16

The inspection included review of nondestructive examination (NDE) procedures,

assessment of NDE personnel training and qualification, and observation and

assessment of Remote Visual (VT) examinations. Discussions were also held with

contractor representatives and other licensee personnel. The inspectors reviewed

results of the licensees 100% Bare Metal Visual (BMV) and VT examination. The

inspectors also performed a visual inspection of the lower head to verify items on the

video tape prior to licensee cleaning of the lower head. The activities and documents

listed below were examined to verify licensee compliance with regulatory requirements

and gather information to help the NRC staff identify possible further regulatory

positions and generic communications.

Specifically, the inspectors reviewed and observed:

-MP/0/A/7150/165, Rx Vessel Bottom Head Bare Metal Inspection, Rev 0

-MP/0/A/7700/080, Inspection, Evaluation and Cleanup of Boric Acid on Plant

Materials.

-QAL-15, Inservice Inspection (ISI) Visual Exam, VT-2, Pressure Test, Rev 20.

-PIP M-03-04004 U2 Rx Vessel Bottom Head Bare Metal Inspection Results

-PIP M-03-04096 Count Room Analysis of Smear Samples

-Video results of VT-2 exam of U2 Rx Bottom Head Inspection

b.

Findings

TI 2515/152 Reporting Requirements:

1.1

Was the examination performed by qualified and knowledgeable personnel?

The Bare Metal Visual (BMV) examination of the reactor vessel (RV) lower head

was conducted by certified visual inspectors to QAL-15, Inservice Inspection

(ISI) Visual Exam, VT-2, Pressure Test. The qualification documentation for the

Level II & Level III VT-2 personnel performing the inspection was verified. The

inspectors also reviewed the inspection standards, acceptance criteria,

calibration requirements of the camera and lighting, the resolution and sensitivity

requirements for the inspection equipment. The inspectors found that the

licencees inspection personnel were very knowledgeable with the requirements

in all of these areas.

1.2

Was the examination performed in accordance with demonstrated procedures?

The inspectors reviewed the applicable inspection procedures and verified they

had been reviewed and approved through the licensees procedure review

process.

The Bare Metal Visual (BMV) examination was performed in accordance with

licensee procedure number MP/0/A/7150/165, Rx Vessel Bottom Head Bare

Metal Inspection.

17

1.3

Was the examination able to identify, disposition, and resolve deficiencies?

The inspectors reviewed the procedures controlling the 100% Bare Metal VT-2

examination techniques and determined that they provided adequate guidance to

ensure that they would be able to identify, disposition and resolve relevant

deficiencies in the RV lower head penetration materials.

1.4

Was the examination capable of identifying pressure boundary leakage and/or

RPV lower head corrosion as described in BL 2003-02?

Based upon review of the results for the BMV examination, procedures,

qualifications, appropriate lighting, and sensitivity requirements, the inspectors

determined that the licensee was capable of identifying and dispositioning

pressure boundary leakage and boric acid corrosion, if present.

2.0

What was the condition of the reactor vessel lower head (debris, insulation, dirt,

boron from other sources, physical layout, viewing obstructions)?

Prior to the RPV lower head inspection all the insulation was removed, and the

reactor vessel bottom head was entirely accessible for the BMV inspection.

Minor boron deposits and metal corrosion were identified on the bottom reactor

vessel and incore guide tubes. In all cases there were visible leak tracks running

down the side of the vessel that originated from previous cavity seal and

sandbox cover seal leaks. Each of the 58 penetrations was videoed twice, one

pass from each side. The combination of the two passes provided a complete

360 degree view of each penetration. No significant boron buildup at the annular

areas around the bottom mounted instrumentation (BMI) penetrations was found

that would indicate a leakage. The inspectors did not see any popcorn type

boric acid crystals surrounding the penetrations. There was no wastage,

corrosion or cracks that needed repair. The inspection results were documented

in PIP M-03-04004, U2 Rx Vessel Bottom Head Bare Metal Inspection Results,

09/07/2003. The inspectors reviewed the video of the bottom head inspection to

verify the licensees inspection results, and held discussions with the appropriate

engineering and examination staff.

3.0

Could small boron deposits, as described in the bulletin, be identified and

characterized?

With the available lighting on the remote visual equipment and the clarity of the

picture, the inspectors were able to verify that the boric acid present on the

bottom head would not mask any indications of penetration leakage. Boron

deposits, as described in the bulletin, could have been readily identified and

characterized.

4.0

What materiel deficiencies (associated with the concerns identified in the

bulletin) were identified that required repair?

18

There was no wastage, corrosion or cracks that needed repair. The licensee was

planning to conduct an additional BMV examination upon completion of hydro-

cleaning the reactor vessel bottom head. This will provide the licensee with

appropriate baseline documentation for future inspections.

5.0

What, if any, impediments to effective examinations were identified.

There were no significant items that could impede effective examinations. The

licensee was able to inspect 360 degrees around each of the 58 lower head

penetration nozzles.

6.0

Did the licensee perform appropriate follow-up examinations for indications of

boric acid leaks from pressure-retaining components above the RPV lower

head?

The Licensee was aware of cavity seal leaks from previous outages. The

licensee plans to hydro-clean the bottom vessel head in order to establish a

baseline visual inspection record for any future BMV examinations.

The licensee obtained residue samples at various locations on the reactor

bottom vessel head, and performed an isotopic analysis. The results verified the

source of the deposits to be from past cavity seal leaks greater than 18 months

old. These results are described in PIP M-03-04096, Count Room Analysis of

Smear Samples.

4OA6 Meetings, Including Exit

On December 18, 2003, the resident inspectors presented the inspection results to

Mr. G. Peterson and other members of his staff. The inspectors confirmed that

proprietary information was not provided or examined during the inspection.

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

D. Black, Security Manager

S. Bradshaw, Superintendent, Plant Operations

J. Bramblett, Chemistry Manager

S. Brown, Manager, Engineering

K. Crane, Technical Specialist

B. Dolan, Manager, Safety Assurance

K. Evans, Manager, Mechanical and Civil Engineering (MCE)

T. Harrall, Station Manager, McGuire Nuclear Station

B. Johanson, SSF System Engineer

R. Kirk, Plant Systems Engineer - PI

L. Loucks, Radiation Protection Manager

R. Parker, Superintendent, Maintenance

G. Peterson, Site Vice President, McGuire Nuclear Station

P. Smith, Maintenance Rule Engineer

J. Thomas, Manager, Regulatory Compliance

K. Thomas, Manager, RES Engineering

B. Travis, Superintendent, Work Control

R. Branch, QA/QTeam Leader

J. Bryant, Regulatory Compliance

D. Caldwell, Inservice Inspection

F. Grass, Insevice Inspection

NRC personnel

R. Haag, Chief, Reactor Projects Branch 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

50-369/03-05-01

NCV

Failure to perform an adequate risk assessment for

removing from service the auxiliary feedwater isolation

valve to the 1D steam generator (Section 1R12)

Closed

50-369, 370/03-07-01

URI

Fire Suppression System for Dedicated Shutdown Areas

Not in Accordance with 10 CFR 50, Appendix R, Section

III.G.3 (Section 4OA5)

Discussed

None

2

LIST OF DOCUMENTS REVIEWED

Section 1R01: (Adverse Weather Protection)

Procedures:

IP/0/B/3250/059, Preventive Maintenance and Operational Check of Freeze Protection, Rev. 15

IP/1/B/3050/013C, FWST Area Temperature Loop Calibration, Rev. 4

IP/0/B/3250/059A, Monthly Check of Freeze Protection, Rev. 14,15

Work Orders:

98585977, Freeze Protection Heat Trace Inspection, dated 8/29/03

98618219, U2 High Temp Normal Heat Trace Control Board Replacement, dated 11/12/03

98289914, U2 Re-Terminate T/C Input Wiring for HT Control, dated 11/19/03

98617629, U1 High Temp Normal Heat Trace Control Board Replacement, dated 11/12/03

98289648,U2 Heat Trace Panel Channel 2 Alarm dated 9/13/03

98606092, Redesign FWST Heat Trace System U2 (Work Order Report), dated 9/4/03

98585977, Inspect Heat Trace, (Work Order Report), dated 10/30/03

PIPs Generated During This Inspection

M-03-05700, Determine If SSF Duct Heaters Needed for Freeze Protection and PMd

M-03-05696, Area Heaters for U1 FWST Instrument Room Not Listed in IP/0/B/3250/095

Section 1R04: (Equipment Alignment)

Partial System Walkdown

Spent Fuel Cooling System Drawing MCFD 1570-01.01

Diesel Generator Engine Flow Diagrams: MCFD-1609-03, Fuel Oil System;

MCFD-1609-01, Cooling Water System; MCFD-1609-04, Starting Air System;

MCFD-1609-02, Lubricating Oil System

Residual Heat Removal Flow Diagram: MCFD-2561-01.00

Complete System Walkdown

Procedure OP/2/A/6200/004, Residual Heat Removal , Revision 071

Training OP-MC-PS-ND, Residual Heat Removal (ND) Lesson Plan, Revision 29

Design Basis Specification -MCS-1561.ND-00-0001, ND System, Revision 8

Drawing MCFD-2561-01.00, Flow Diagram of ND System", Revision10

UFSAR section 6.3, Emergency Core Cooling System

UFSAR section 5.5.7, Residual Heat Removal

WR 98623147 2NDPS5040: Top Left T-Valve Has Leak

WR 98624377 2NDTE7500: Reinstall Upper Thermocouple

WR 98618960 2NDTE7500: Check Upper Bearing T/C

WR 98618403 2ND-19A: Replace Add-On Pack of Actuator

3

PIP M-03-04545, Miniflow Recirc via 2ND-68A has decreased from 667 to 587 gpm

PIP M-03-02170, 2NDPS 5040 Locking Screw for Low Switch Found Stripped

PIP M-01-04677, 1/2ND-14,29, & 34 Present Special System Vulnerabilities

PIP M-03-01236, Operating Experience Evaluation of IN 2003-03, Part 21 Inadequately Staked

Capscrew Renders Residual Heat Removal Pump Inoperable

IN-2003-03, Part 21 - Inadequately Staked Capscrew Renders Residual Heat Removal Pump

Inoperable

2003T2, ND - Residual Heat Removal and Low Head Safety Injection Health Report

2003T2, Air Operated Valves Health Report

Section1R05: (Fire Protection)

Procedures:

McGuire Nuclear Station IPEEE Submittal Report dated June 1, 1994

McGuire Nuclear Station Supplemental IPEEE Fire Analysis Report dated August 1, 1996

MCS-1465.00-00-0008, R4, Design Basis Specification for Fire Protection

Drawings: MC-1384-07-17-01, MC-1384-07-13-01, MC-1384-07-15-01, MC-1384-07-15-01

Section 1R06: (Flood Protection Measures)

UFSAR Sections

2.4.10, Flooding Protection Requirements.

3.6A.6, Flooding Analysis.

Calculations:

MCC-1223.42-00-0037, Evaluation of the Use of Non-Safety Water Sources for the Auxiliary

Feedwater System, Sec. 10.8, Rev. 6

MCC-1206.47-69-1001, Auxiliary Building Flooding Analysis, Sec.9.2-9.2.1, Rev. 11

Procedures:

AP/0/A/5500/44, Plant Flooding, Rev. 3

IP/0/A/3215/004, Magnetrol Liquid Level Control Switch Calibration, Rev. 15

ML040130636

Text

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