ML080350426

IR 05000325-07-005, 05000324-07-005; on 10/01/07- 12/31/07; Brunswick Steam Electric Plant, Units 1 and 2

ML080350426
Person / Time
Site:	Brunswick
Issue date:	01/29/2008
From:	Randy Musser Division Reactor Projects II
To:	Waldrep B Carolina Power & Light Co
References
IR-07-005
Download: ML080350426 (23)

See also: IR 05000324/2007005

Text

January 29, 2008

Carolina Power and Light Company

ATTN: Mr. Benjamin Waldrep

Vice President

Brunswick Steam Electric Plant

P. O. Box 10429

Southport, NC 28461

SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION

REPORT NOS. 05000324/2007005 AND 05000325/2007005

Dear Mr. Waldrep:

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

inspection at your Brunswick Units 1 and 2 facilities. The enclosed integrated inspection report

documents the inspection findings, which were discussed on January 22, 2008, with you and

other members of your staff.

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

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed

personnel.

On the basis of the results of this inspection, no findings of significance were identified.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter

and its enclosure will be available electronically for public inspection in the NRC Public

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

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

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

Sincerely,

/RA/

Randall A. Musser, Chief

Reactor Projects Branch 4

Division of Reactor Projects

Docket Nos.: 50-325, 50-324

License Nos: DPR-71, DPR-62

Enclosure: Inspection Report 05000325, 324/2007005

w/Attachment: Supplemental Information

cc w/encl: (See page 2)

OFFICE RII:DRP RII:DRP RII:DRP RII:DRS RII:DRS RII:DRS RII:DRS

SIGNATURE /RA/ /RA By e-mail/ /RA by e-mail/ /RA/

NAME R Musser J Austin S Rutledge G Wilson

DATE 1/29/08 1/30/08 1/30/08 1/29/08

E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO

CP&L 2

cc w/encl:

Director, Site Operations John H. O'Neill, Jr.

Brunswick Steam Electric Plant Shaw, Pittman, Potts & Trowbridge

Carolina Power & Light Company 2300 N. Street, NW

Electronic Mail Distribution Washington, DC 20037-1128

J. Paul Fulford, Manager Beverly Hall, Chief, Radiation

Performance Evaluation and Protection Section

Regulatory Affairs PEB 5 N. C. Department of Environment

Carolina Power & Light Company and Natural Resources

Electronic Mail Distribution Electronic Mail Distribution

Terry D. Hobbs, Plant General Manager Peggy Force

Brunswick Steam Electric Plant Assistant Attorney General

Carolina Power & Light Company State of North Carolina

P. O. Box 10429 Electronic Mail Distribution

Southport, NC 28461

Chairman of the North Carolina

Donald L. Griffith Utilities Commission

Manager - Training c/o Sam Watson, Staff Attorney

Progress Energy Carolinas, Inc. Electronic Mail Distribution

Brunswick Steam Electric Plant

Electronic Mail Distribution Robert P. Gruber

Executive Director

Randy C. Ivey Public Staff NCUC

Manager - Support Services 4326 Mail Service Center

Progress Energy Carolinas, Inc. Raleigh, NC 27699-4326

Brunswick Steam Electric Plant

Electric Mail Distribution Public Service Commission

State of South Carolina

Garry D. Miller, Manager P. O. Box 11649

License Renewal Columbia, SC 29211

Progress Energy

Electronic Mail Distribution David R. Sandifer

Brunswick County Board of

Annette H. Pope, Supervisor Commissioners

Licensing/Regulatory Programs P. O. Box 249

Carolina Power and Light Company Bolivia, NC 28422

Electronic Mail Distribution

Warren Lee

David T. Conley Emergency Management Director

Associate General Counsel - Legal Dept. New Hanover County Department of

Progress Energy Service Company, LLC Emergency Management

Electronic Mail Distribution 230 Government Center Drive

Suite 115

James Ross Wilmington, NC 28403

Nuclear Energy Institute

Electronic Mail Distribution

CP&L 3

Report to Ben Waldrep from Randall A. Musser dated January 29, 2008

SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION

REPORT NOS. 05000324/2007005 AND 05000325/2007005

Distribution w/encl:

S. Bailey, NRR

R. Pascarelli, NRR

C. Evans, RII

L. Slack, RII

RIDSNRRDIRS

OE Mail

PUBLIC

NRC Resident Inspector

U.S. Nuclear Regulatory Commission

8470 River Road, SE

Southport, NC 28461

U. S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos: 50-325, 50-324

License Nos: DPR-71, DPR-62

Report Nos: 05000325/2007005 and 05000324/2007005

Licensee: Carolina Power and Light (CP&L)

Facility: Brunswick Steam Electric Plant, Units 1 & 2

Location: 8470 River Road SE

Southport, NC 28461

Dates: October 1, 2007 through December 31, 2007

Inspectors: J. Austin, Senior Resident Inspector

S. Rutledge, Resident Inspector

Approved by: Randall A. Musser, Chief

Reactor Projects Branch 4

Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000325/2007005, 05000324/2007005; 10/01/07- 12/31/07; Brunswick Steam

Electric Plant, Units 1 and 2.

The report covered a 3-month period of inspection by resident inspectors and one senior

reactor inspector. One Green non-cited violation (NCV) was identified. The significance

of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection

Manual Chapter (IAC) 0609, Significance Determination Process (SDP). The NRC's

program for overseeing the safe operation of commercial nuclear power reactors is

described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December

2006.

A. NRC-Identified and Self-Revealing Findings

NONE

B. Licensee-Identified Findings

NONE

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1

Unit 1 began the inspection period operating at full power. On October 6, power was

reduced to 93 percent to perform a control rod improvement. The unit was restored to

full power the same day. On October 13, power was reduced to 93 percent to perform a

control rod improvement. The unit was returned to full power the same day. On

October 20, power was reduced to 93 percent to perform a control rod improvement.

Full power was restored the same day. On October 27, power was reduced to 93

percent to perform a control rod improvement. Full power was achieved later that day.

On November 3, power was reduced to 67 percent to facilitate valve testing. The unit

was returned to full power later that day. On November 4, power was reduced to 95

percent to perform a control rod improvement. Full power was restored on November 5.

On November 11, power was reduced to 90 percent to perform a control rod

improvement. Full power was achieved later that day. On November 16, power was

reduced to 91 percent to perform a control rod improvement. The unit was returned to

full power November 17. On November 24, power was reduced to 90 percent for control

rod testing. Full power was restored later that day. The unit remained at full power for

the remainder of the inspection period.

Unit 2

Unit 2 began the inspection period operating at full power. On October 1, a power

ascension occurred from main turbine valve testing. Full power was restored later that

day. On October 1, power was reduced to 95 percent to perform a control rod

improvement. Full power was restored later that day. On October 1, power was

reduced to 96 percent to perform a control rod improvement. The unit was returned to

full power later that day. On October 2, power was reduced to 98 percent to perform a

control rod improvement. Full power was restored later that day. On November 8,

power was reduced to 71 percent for a Whiteville line outage. Power was returned to

full later that day. On November 9, power was reduced to 98 percent for a control rod

improvement. Full power was restored later that day. On November 17, power was

reduced to 68 percent for main turbine valve, reactor feed pump and scram time testing.

The unit was returned to full power on November 18. On November 18, power was

reduced to 94 percent for xenon build-up following main turbine valve testing and control

rod sequence exchange. Full power was returned on November 19. On November 19,

power was reduced to 85 percent to perform a control rod improvement. Full power was

restored November 20. On November 20, power was reduced to 95 percent to perform

a control rod improvement. Full power was achieved November 21, 2007. The unit

remained at full power for the remainder of the inspection period.

Enclosure

3

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

The inspectors assessed the effectiveness of the licensees cold weather protection

program as it related to ensuring that the facilitys service water pumps, emergency

diesel generators, and condensate storage tank low level switches would remain

functional and available in cold weather conditions. In addition to reviewing the

licensees program-related documents and procedures, walkdowns were conducted of

the freeze protection equipment (e.g., heat tracing, area space heaters, etc.) associated

with the above systems/components. Licensee problem identification and resolution

associated with cold weather protections was also assessed.

• AR 246713246713 Unit 2 condensate storage tank heat trace inoperable

• AR 253047253047 Emergency diesel generator #1 jacket water heater temperature

switch

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed three partial walkdowns of the below-listed systems to verify

that the systems were correctly aligned while the redundant train or system was

inoperable or out-of-service (OOS) or, for single train risk significant systems, while the

system was available in a standby condition. The inspectors assessed conditions such

as equipment alignment (i.e., valve positions, damper positions, and breaker alignment)

and system operational readiness (i.e., control power and permissive status) that could

affect operability. The inspectors verified that the licensee identified and resolved

equipment alignment problems that could cause initiating events or impact mitigating

system availability. The inspectors reviewed Administrative Procedure

ADM-NGGC-0106, Configuration Management Program Implementation, to verify that

available structures, systems or components (SSCs) met the requirements of the

configuration control program. Documents reviewed are listed in the Attachment.

• 2A Nuclear service water pump when the 2B nuclear service water pump was

OOS for scheduled maintenance on October 3, 2007

Enclosure

4

• Unit 2 RCIC when the Unit 2 HPCI was OOS for seal repair on October 15, 2007

• EDG #2, #3, and #4 while EDG #1 was OOS for scheduled maintenance on

November 19, 2007

To assess the licensees ability to identify and correct problems, the inspectors reviewed

the following Action Requests (ARs):

• AR 251684251684 RCIC extent of condition evaluation using Panametrics

• AR 252203252203 U2 RCIC seal purge line orifice missing

• AR 259682259682 U1 RCIC steam supply drain pot steam leak

• AR 254033254033 EDG starting air pilot air lines support discrepancies

• AR 254280254280 EDG #3 brush inspection meg readings

• AR 259504259504 EDG #1 generator vibration alarm

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors conducted a detailed review of the alignment and condition of the Unit 2

high pressure coolant injection system. The inspector reviewed the Updated Final

Safety Analysis Report, associated attachments of Operating Procedure 2OP-19, High

Pressure Coolant Injection System Operating Procedure, 0PT-09.2, HPCI System

Operability Test and the systems diagrams (drawing numbers D-02523 and LL-09272)

in determining correct system lineup. The inspectors also reviewed maintenance history

of the system.

To assess the licensees identification and resolutions of problems, the inspectors

reviewed the following:

• AR 250203250203 HPCI inoperable due to pump seal leakage

• AR 225856225856 HPCI lube oil coolers debris

• AR 229349229349 HPCI condensate pump trip

• AR 251647251647 U2 HPCI vacuum tank level issues

• AR 251490251490 Water in U2 HPCI lube oil

b. Findings

No findings of significance were identified.

Enclosure

5

1R05 Fire Protection

.1 Fire Area Walkdowns

a. Inspection Scope

The inspectors reviewed ARs and work orders (WOs) associated with the fire

suppression system to confirm that their disposition was in accordance with Procedure

0AP-033, Fire Protection Program Manual. The inspectors reviewed the status of

ongoing surveillance activities to verify that they were current to support the operability

of the fire protection system. In addition, the inspectors observed the fire suppression

and detection equipment to determine whether any conditions or deficiencies existed

which would impair the operability of that equipment. The inspectors toured the

following six areas important to reactor safety and reviewed the associated prefire plans

to verify that the requirements for fire protection design features, fire area boundaries,

and combustible loading were met. Documents reviewed are listed in the Attachment.

• Units 1 and 2 Control Building, - 49' elevation (2 areas)

• Units 1 and 2 Control Building, - 23' elevation (2 areas)

• Units 1 and 2 Reactor Building - 17' elevation (2 areas)

b. Findings

No findings of significance were identified.

.2 Fire Drill

a. Inspection Scope

On October 6, 2007, the inspectors observed a plant fire drill at the auxiliary boiler unit

located outside near the Emergency Diesel Generator Building, to assess the fire

brigade performance and to verify that proper firefighting techniques for the type of fire

encountered were utilized. The inspectors monitored the fire brigades use of protective

equipment and firefighting equipment to verify that preplanned firefighting procedures

and appropriate firefighting techniques were used, and to verify that the directions of the

fire brigade leader were thorough, clear, and effective. The inspectors attended the

critique to confirm that appropriate feedback on performance was provided to brigade

members and to ensure that areas for improvement were properly identified for licensee

follow-up. In preparing for the drill, the inspectors reviewed the preplanned drill

scenario, Brunswick Nuclear Plant Drill Scenario Guide, 99-F-0S, Revision 1.

b. Findings

No findings of significance were identified.

Enclosure

6

1R06 Flood Protection Measures

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed the licensees internal flooding analysis as described in

Updated Final Safety Analysis Report (UFSAR) Section 3.4.2, Protection From Internal

Flooding. Due to the risk significance of equipment in the Service Water and

Emergency Diesel Generator Buildings, the inspectors reviewed UFSAR Section 3.4.2

analysis of the effects of postulated piping failures for these two areas to determine if

the analysis assumptions and conclusions were based on the current plant

configuration. The internal flooding design features and equipment for coping with

internal flooding was inspected for the equipment located in these buildings. The

walkdown included sources of flooding and drainage, sump pumps, level switches,

watertight doors, curbs, pedestals and equipment mounting. Documents reviewed are

listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 External Flooding

a. Inspection Scope

The inspectors reviewed the licensees external flooding analysis as described in

UFSAR Section 3.4.1, Protection from External Flooding, to determine the external flood

control design features. Walkdowns were conducted to inspect the external flood

protection barriers including watertight doors, curbs, sealing of external building

penetrations below flood line, and the sump pumps and level alarm circuits. Areas

reviewed included the Emergency Diesel Generator Building, and the Service Water

Building. The inspector reviewed the procedures for coping with external flooding

contained in Abnormal Operating Procedure (AOP) 0AOP-13.0, Operation During

Hurricane, Flood Conditions, Tornado, or Earthquake. Other documents reviewed are

listed in the Attachment.

b. Findings

No findings of significance were identified.

Enclosure

7

1R11 Licensed Operator Requalification

.1 Quarterly Review

a. Inspection Scope

The inspectors observed licensed operator performance and reviewed the associated

training documents during annual dynamic simulator examination sessions for training

cycle 2007-05. The simulator observations and review included evaluations of

emergency operating procedure and abnormal operating procedure utilization. The

inspectors reviewed Procedure 0TPP-200, Licensed Operator Continuing Training

Program, to verify that the program ensures safe power plant operation. Simulator

sessions were observed on November 20, 2007. The scenarios tested the operators

ability to respond to secondary plant failures, loss of emergency power, and an

automatic trip without a scram followed by a rupture of the scram discharge volume.

The inspectors reviewed operator activities to verify consistent clarity and formality of

communication, conservative decision-making by the crew, appropriate use of

procedures, and proper alarm response. Group dynamics and supervisory oversight,

including the ability to properly identify and implement appropriate Technical

Specification (TS) actions, regulatory reports, and notifications, were observed. The

inspectors observed instructor critiques and preliminary grading of the operating crews

and assessed whether appropriate feedback was planned to be provided to the licensed

operators.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the two equipment issues described in the ARs listed below, the inspectors reviewed

the licensees implementation of the Maintenance Rule (10 CFR 50.65) with respect to

the characterization of failures, the appropriateness of the associated Maintenance Rule

a(1) or a(2) classification, and the appropriateness of the associated a(1) goals and

corrective actions. The inspectors reviewed the work controls and work practices

associated with the degraded performance or condition to verify that they were

appropriate and did not contribute to the issue. The inspectors also reviewed operations

logs and licensee event reports to verify unavailability times of components and

systems, if applicable. Licensee performance was evaluated against the requirements

of Procedure ADM-NGGC-0101, Maintenance Rule Program.

• AR 242066242066 BNP response to operating experience 2007-08 degradation of

buried piping

• AR 256103256103 Loss of full out indications on the full core display

Enclosure

8

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

The inspectors reviewed the licensees implementation of 10 CFR 50.65 (a)(4)

requirements during scheduled and emergent maintenance activities, using Procedure

0AP-025, BNP Integrated Scheduling and Technical Requirements Manual 5.5.13,

Configuration Risk Management Program. The inspectors reviewed the effectiveness of

risk assessments performed due to changes in plant configuration for maintenance

activities (planned and emergent). The review was conducted to verify that, upon

unforseen situations, the licensee had taken the necessary steps to plan and control the

resultant emergent work activities. The inspectors reviewed the applicable plant risk

profiles, work week schedules, and maintenance WOs for the following five conditions:

• AR 250203250203 HPCI inoperable due to pump seal leakage

• AR 255545255545 Unexpected annunciators during performance test (PT-12.2a) for

EDG #1

• AR 257721257721 Unit 1 condensate storage tank instrumental vent line excessive

sloping

• AR 257744257744 EDG #3 jacket water leakage from flexmaster jumpers

• AR 256079256079 1-E11-F017B inoperable due to high energy line break issues at the

motor control cubicle compartment

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the operability evaluations associated with the six issues

documented in the ARs listed below, which affected risk significant systems or

components, to assess, as appropriate: 1) the technical adequacy of the evaluations; 2)

the justification of continued system operability; 3) any existing degraded conditions

used as compensatory measures; 4) the adequacy of any compensatory measures in

place, including their intended use and control; and 5) where continued operability was

considered unjustified, the impact on any TS limiting condition for operation and the risk

significance. In addition to the reviews, discussions were conducted with the applicable

system engineer regarding the ability of the system to perform its intended safety

function.

Enclosure

9

• AR 249130249130 1A Residual heat removal heat exchanger degradation during

testing (OPF08.1.4A)

• AR 245864245864 E-4 Loss of coolant accident logic relay 27E2 de-energized

• AR 250793250793 Unit 2 RCIC operability concern

• AR 252203252203 Unit 2 RCIC seal purge line orifice missing

• AR 251885251885 Unit 2 HPCI main pump seal leak exceeds posting

• AR 251490251490 Water in Unit 2 HPCI lube oil

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

For the five maintenance activities listed below, the inspectors reviewed the post-

maintenance test procedure and witnessed the testing and/or reviewed test records to

confirm that the scope of testing adequately verified that the work performed was

correctly completed. The inspectors verified that the test demonstrated that the affected

equipment was capable of performing its intended function and was operable in

accordance with TS requirements. The inspectors reviewed the licensees actions

against the requirements in Procedure 0PLP-20, Post Maintenance Testing Program.

• PT 9.2 HPCI Operability Test following inboard seal failure

• WO 114145 RCIC system fill and vent after pump maintenance

• WO 1137349 Inspection of HPCI sump after drain down

• AR 250499250499 Basis for changing piping test plan not understood

• AR 247456247456 Balance of plant under-voltage relays not tested as required

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

.1 Routine Surveillance Testing

a. Inspection Scope

The inspectors either observed surveillance tests or reviewed test data for the three risk

significant SSC surveillances, listed below, to verify the tests met TS surveillance

requirements, UFSAR commitments, in-service testing (IST) requirements, and licensee

procedural requirements. The inspectors assessed the effectiveness of the tests in

demonstrating that the SSCs were operationally capable of performing their intended

safety functions.

Enclosure

10

• 0PT-09.2mst-HPCI 23Q, High Pressure Coolant Injection System operability test,

performed on Unit 2 on October 22, 2007

• 2O1-03.2, Control Operator Daily Surveillance Report (including drywell leakage

rate determination), performed the week of November 12, 2007.

C 0PT-9.3a, High Pressure Coolant Injection System Component Test, performed

on Unit 1 on December 7, 2007.

b. Findings

No findings of significance were identified.

.2 In-service Surveillance Testing

a. Inspection Scope

The inspectors reviewed the performance of Periodic Test 0PT-9.7, High Pressure

Coolant Injection System Valve Operability Test, performed on Unit 1 on December 7,

2007. The inspectors evaluated the effectiveness of the licensees American Society of

Mechanical Engineers (ASME)Section XI testing program to determine equipment

availability and reliability. The inspectors evaluated selected portions of the following

areas: 1) testing procedures; 2) acceptance criteria; 3) testing methods; 4) compliance

with the licensees IST program, TS, selected licensee commitments, and code

requirements; 5) range and accuracy of test instruments; and 6) required corrective

actions. The inspectors also assessed any applicable corrective actions taken.

To assess the licensees ability to identify and correct problems, the inspector reviewed

AR 214876214876which documented that the Unit 1 A conventional service water pump was

discovered to be in the Alert range following testing on November 30, 2006.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed site emergency preparedness training drill/simulator scenarios

conducted on October 30, 2007 and November 8, 2007. The inspectors reviewed the

drill scenario narrative to identify the timing and location of classifications, notifications,

and protective action recommendations development activities. The inspectors

evaluated the drill conduct from the control room simulator, technical support center,

and the emergency operations facility. During the drill, the inspectors assessed the

adequacy of event classification and notification activities. The inspectors observed

portions of the licensees post-drill critiques at the technical support center and

emergency operating facility.

Enclosure

11

The inspectors verified that the licensee properly evaluated the drills performance with

respect to performance indicators and assessed drill performance with respect to drill

objectives. To assess the ability of the licensee to identify and correct problems, the

inspectors reviewed the following corrective action documents that were generated as a

result of the drill:

• AR 252936252936 knowledge gap in the required actions associated with the Reactor

Building positive pressure as defined in AST documentation

• AR 252937252937 rewording of SPDS indication to prevent human error

• AR 254108254108 JIC positions not filled during ERO drill

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed Operating Manual 0PLP-22, Temporary Changes, to assess

the implementation of Engineering Change (EC) 67830, Reactor Core Isolation Cooling

System Low Suction Pressure Trip Delay which was implemented on October 21, 2007.

The inspectors reviewed the EC to verify that the modification did not affect the

functional capability of the EDG, that the modification was properly installed, and

appropriate post-installation testing was performed.

b. Findings

No findings of significance were identified.

4. OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors sampled licensee data for the performance indicators (PIs) listed below.

To verify the accuracy of the PI data reported during the period reviewed, PI definitions

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

5 were used to verify the basis for each data element.

Reactor Safety Cornerstone

The inspectors sampled licensee submittals for the Units 1 and 2 PIs listed below for the

period January 2007 through November 2007.

Enclosure

12

• High Pressure Coolant Injection System

• Reactor Core Isolation Cooling System

A sample of plant records and data was reviewed and compared to the reported data to

verify the accuracy of the PIs. The licensees corrective action program records were

also reviewed to determine if any problems with the collection of PI data had occurred.

Documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of ARs

To aid in the identification of repetitive equipment failures or specific human

performance issues for followup, the inspectors performed frequent screenings of items

entered into the licensees CAP. The review was accomplished by reviewing daily ARs.

.2 Annual Sample Review

a. Inspection Scope

The inspectors performed an in-depth annual sample review of plant operator

workarounds as documented in licensees operator workaround program and corrective

action documents. This review was performed to verify that the licensee identified

operator workarounds at an appropriate threshold, entered the issues into the CAP, and

planned or implemented appropriate corrective actions. The inspectors reviewed the

actions taken to verify that the licensee had adequately addressed the following

attributes:

• Complete, accurate, and timely identification of the problem

• Evaluation and disposition of operability and reportability issues

• Consideration of previous failures, extent of condition, generic or common cause

implications

• Prioritization and resolution of the issue commensurate with the safety

significance

• Identification of the root cause and contributing causes of the problem

• Identification and implementation of corrective actions commensurate with the

safety significance of the issue

The inspectors reviewed the associated corrective action for AR 250203250203 Unit 2 high

pressure coolant injection pump seal failure that occurred on October 10, 2007.

Enclosure

13

b. Findings and Observations

No findings of significance were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to

identify trends that could indicate the existence of a more significant safety issue. The

review was focused on repetitive equipment issues but also considered the results of

frequent inspector CAP item screening (discussed above), licensee trending efforts, and

licensee human performance results. The review considered the period of July through

December 2007. The review further included issues documented outside the normal

CAP in major equipment lists, repetitive and/or rework maintenance lists, operational

focus list, control room deficiency list, outstanding work order list, quality assurance

audit/surveillance reports, key performance indicators, and self-assessment reports.

The inspectors compared and contrasted their results with the results contained in

multiple root cause evaluations the licensee has performed over the last 2 quarters.

Corrective actions associated with a sample of the issues identified in the licensees

trend reports were reviewed for adequacy. The inspectors also evaluated the reports

against the requirements of the licensees CAP as specified in Nuclear Generation

Group Standard Procedure CAP-NGGC-0200, Corrective Action Program, and 10 CFR

50, Appendix B.

b. Assessment and Observations

No findings of significance were identified. The inspectors noted a trend in the control

and retrieval of foreign material in systems and the adverse effects this has had on

system performance; this was exemplified by the following identified issues:

1) Foreign material found in the 1B Residual Heat Removal (RHR) Room cooler

(AR243465243465; 2) Metallic foreign material found in the 1B RHR Heat Exchanger

(AR246790246790; 3) 1D RHRSW Booster pump failed to start was bound by valve pin (AR

243867); 4) Unit 2 HPCI main pump inboard seal failure due to blockage of seal cooling

line (AR250203250203. The inspectors have determined that the licensee has addressed all

immediate operability concerns, and is currently developing long-term improvements.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On January 24, 2008, the resident inspectors presented the inspection results to

Mr. Waldrep and other members of his staff. The inspectors confirmed that proprietary

information was not provided or examined during the inspection.

ATTACHMENT: SUPPLEMENTAL INFORMATION

Enclosure

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Atkinson, Supervisor - Emergency Preparedness

L. Beller, Superintendent Operations Training

A. Brittain, Manager - Security

D. Griffith, Manager - Training Manager

L. Grzeck, Lead Engineer - Technical Support

S. Howard, Manager - Operations

R. Ivey, Manager - Site Support Services

T. Pearson, Supervisor - Operations Training

A. Pope, Supervisor - Licensing/Regulatory Programs

S. Rogers, Manager - Maintenance

B. Waldrep, Site Vice President

T. Sherrill, Engineer - Technical Support

T. Trask, Manager - Engineering

J. Titrington, Manger - Nuclear Assessment Services

M. Turkal, Lead Engineer - Technical Support

M. Williams, Manager - Operations Support

E. Wills, Plant General Manager

NRC Personnel

Randall Musser, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

None

Discussed

None

LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

Plant Operating Manual (POM), Volume VII, Operating Instruction 0OI-01.03, Non-Routine

Activities

POM, Volume XII, Preventive Maintenance 0PM-HT001, Preventive Maintenance on Plant

Freeze Protection and Heat Tracing System

Section 1R04: Equipment Alignment

POM, Volume III, Operating Procedure 2OP-39, High Pressure Coolant Injection System

Operating Procedure

POM, Volume III, 0OP-39, Diesel Generator Operating Procedure

System Description SD-39, Emergency Diesel Generators

Section 1R05: Fire Protection

POM, Volume XIX, Prefire Plan 0PFP-DG, Diesel Generator Building Prefire Plans

POM, Volume XIX, Prefire Plan 0PFP-PBAA, Power Block Auxiliary Areas Prefire Plans

POM, Volume XIX, Prefire Plan 1PFP-RB, Unit 1 Reactor Building Prefire Plans

Section 1R06: Flood Protection Measures

POM, Volume XXI, Abnormal Operating Procedure (AOP) 0AOP-13.0, Operation During

Hurricane, Flood Conditions, Tornado, or Earthquake

POM, Volume X, Periodic Test (PT) 0PT-34.2.2.1, Fire Door, ASSD Access/Egress Door,

Severe Weather Door Inspections

Updated Final Safety Analysis Report Chapters 2 and 3

Attachment