ML092110250

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IR 05000325-09-003, 05000324-09-003, on 4/01/2009 - 6/30/2009, Brunswick Steam Electric Plant, Units 1 & 2; Refueling and Other Outage Activities
ML092110250
Person / Time
Site: Brunswick  Duke Energy icon.png
Issue date: 07/30/2009
From: Randy Musser
NRC/RGN-II/DRP/RPB4
To: Waldrep B
Carolina Power & Light Co
References
IR-09-003
Download: ML092110250 (32)
v • d • e


See also: IR 05000324/2009003

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION II

SAM NUNN ATLANTA FEDERAL CENTER

61 FORSYTH STREET, SW, SUITE 23T85

ATLANTA, GEORGIA 30303-8931

July 30, 2009

Mr. Benjamin C. Waldrep

Vice President

Carolina Power and Light Company

Brunswick Steam Electric Plant

P. O. Box 10429

Southport, NC 28461

SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED

INSPECTION REPORT NOS.: 05000325/2009003 AND

05000324/2009003

Dear Mr. Waldrep:

On June 30, 2009, the US Nuclear Regulatory Commission (NRC) completed an inspection at

your Brunswick Unit 1 and 2 facilities. The enclosed integrated inspection report documents the

inspection findings, which were discussed on July 16, 2009, with Mr. Ben Waldrep 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.

This report documents one self-revealing finding of very low safety significance (Green). This

finding was determined to involve violations of NRC requirements. However, because of the

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

NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the

NRCs Enforcement Policy. If you contest any NCV, you should provide a response within 30

days of the date of this inspection report, with the basis for your denial, to the Nuclear

Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001, with

copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United

States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident

Inspector at the Brunswick Steam Electric Plant. In addition, if you disagree with the

characterization of any finding in this report, you should provide a response within 30 days of

the date of this inspection report, with the basis for your disagreement, to the Regional

Administrator, Region II, and the NRC Resident Inspector at the Brunswick Steam Electric

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

Chapter 0305.

CP&L 2

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its

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

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

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/

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, 324/2009003

w/Attachment: Supplemental Information

cc w/encl: (See page 3)

_________________________ XG SUNSI REVIEW COMPLETE

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

SIGNATURE JGW1 PBO GJK2 PBL1 RCC2 RPC1 RAM

NAME JWorosilo POBryan GKolcum PLessard RChou RCarrion RMusser

DATE 0729/2009 07/29/2009 07/29/2009 07/30/2009 0729/2009 07/29/2009 07/30/2009

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

CP&L 3

cc w/encl:

R. J. Duncan, II, Vice President Garry D. Miller, Manager

Nuclear Operations License Renewal

Carolina Power & Light Company Progress Energy

Electronic Mail Distribution Electronic Mail Distribution

Michael J. Annacone Gene Atkinson

Director Site Operations Supervisor, Licensing/Regulatory Programs

Brunswick Steam Electric Plant Brunswick Steam Electric Plant

Progress Energy Carolinas, Inc. Progress Energy Carolinas, Inc.

Electronic Mail Distribution Electronic Mail Distribution

Edward L. Wills, Jr. Senior Resident Inspector

Plant General Manager Carolina Power and Light Company

Brunswick Steam Electric Plant Brunswick Steam Electric Plant

Progress Energy Carolinas, Inc. U.S. NRC

Electronic Mail Distribution 8470 River Road, SE

Southport, NC 28461

Benjamin C. Waldrep, Vice President

Brunswick Steam Electric Plant John H. O'Neill, Jr.

Progress Energy Carolinas, Inc. Shaw, Pittman, Potts & Trowbridge

Electronic Mail Distribution 2300 N. Street, NW

Washington, DC 20037-1128

Christos Kamilaris, Director

Fleet Support Services Peggy Force, Assistant Attorney General

Carolina Power & Light Company State of North Carolina

Electronic Mail Distribution P.O. Box 629

Raleigh, NC 27602

Thomas D. Walt, Vice President

Nuclear Oversight Chairman, North Carolina Utilities

Carolina Power and Light Company Commission

Electronic Mail Distribution Electronic Mail Distribution

Brian C. McCabe Robert P. Gruber, Executive Director

Manager, Nuclear Regulatory Affairs Public Staff - NCUC

Progress Energy Carolinas, Inc. 4326 Mail Service Center

Electronic Mail Distribution Raleigh, NC 27699-4326

Phyllis N. Mentel David R. Sandifer

Manager, Support Services Brunswick County Board of Commissioners

Brunswick Steam Electric Plant P.O. Box 249

Progress Energy Carolinas, Inc. Bolivia, NC 28422

Electronic Mail Distribution

James Ross

Donald L. Griffith Nuclear Energy Institute

Manager Electronic Mail Distribution

Brunswick Steam Electric Plant

Progress Energy Carolinas, Inc. cc w/encl. (Continued next page)

Electronic Mail Distribution

CP&L 4

cc w/encl. (Continued)

Public Service Commission

State of South Carolina

P.O. Box 11649

Columbia, SC 29211

Beverly O. Hall

Chief, Radiation Protection Section

Department of Environmental Health

N.C. Department of Environmental Commerce & Natural Resources

Electronic Mail Distribution

Warren Lee

Emergency Management Director

New Hanover County Department of Emergency Management

230 Government Center Drive

Suite 115

Wilmington, NC 28403

CP&L 5

Letter to Benjamin C. Waldrep from Randall A. Musser dated July 30, 2009

SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED

INSPECTION REPORT NOS.: 05000325/2009003 AND

05000324/2009003

Distribution w/encl:

C. Evans, RII EICS

L. Slack, RII EICS

OE Mail

RIDSNRRDIRS

PUBLIC

RidsNrrPMBrunswick Resource

U. S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos.: 50-325, 50-324

License Nos.: DPR-71, DPR-62

Report Nos.: 05000325/2009003, 05000324/2009003

Licensee: Carolina Power and Light (CP&L)

Facility: Brunswick Steam Electric Plant, Units 1 & 2

Location: 8470 River Road, SE

Southport, NC 28461

Dates: April 1, 2009 through June 30, 2009

Inspectors: P. OBryan, Senior Resident Inspector

G. Kolcum, Resident Inspector

P. Lessard, Resident Inspector, Harris

R. Chou, Reactor Inspector (1R07)

R. Carrion, Senior Reactor Inspector (1R07)

Approved by: Randall A. Musser, Chief

Reactor Projects Branch 4

Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000325/2009003, 05000324/2009003; 4/01/2009 - 6/30/2009; Brunswick Steam Electric

Plant, Units 1 & 2; Refueling and Other Outage Activities.

This report covers a three-month period of inspection by resident inspectors and announced

baseline inspections by regional inspectors. One Green non-cited violation (NCV) was identified

by the inspectors. The significance of most findings is indicated by their color (Green, White,

Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination

Process (SDP). The cross cutting aspect was determined using IMC 0305, Operating Reactor

Assessment Program. Findings for which the SDP does not apply may be Green or be

assigned a severity level after NRC management review.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

Administrative Control (Procedures), was identified when the licensee failed to

follow plant procedure OPT-80.1, Reactor Pressure Vessel (RPV) ASME Section

XI Pressure Test during Unit 2 RPV hydrostatic testing on April 7, 2009. The

licensee installed hoses rated for 250 psig although the procedure required

hoses rated at 1150 psig. Specifically, when RPV pressure was raised to

approximately 1000 psig, the improper hose installed at core spray check valve

2-E21-F006B disconnected from its coupling, causing the RPV to rapidly

depressurize to approximately 875 psig and allowing water from the RPV to leak

out of the connection into the drywell. The licensee discovered the leak and

broken hose connection, isolated the leak, and initiated AR329675329675to address

this issue.

The finding was determined to be more than minor because the finding was

associated with the Initiating Events cornerstone attribute of human performance

and affected the cornerstone objective of limiting the likelihood of those events

that upset plant stability and challenge critical safety functions during shutdown

as well as power operations. The inspectors determined that the finding should

be evaluated in accordance with Attachment 1 of IMC 0609, Appendix G,

Shutdown Operations SDP. The inspectors used Checklist 8 contained in

Attachment 1 and determined that the finding did require a phase 2 or phase 3

because the licensee did not meet the appropriate safety function guidelines for

inventory control. Specifically, the finding increases the likelihood of a loss of

RCS inventory. The regional Senior Reactor Analyst (SRA) determined, after a

teleconference with the headquarters SRA with responsibility for Shutdown

findings, that the event did not rise to a level that would require a detailed

analysis be performed. The event did not meet the threshold for a loss of control

as defined by Appendix G. Additional margin was provided by the high elevation

of the leak relative to the top of active fuel, and the suction head requirement of

the residual heat removal (RHR) system, the small size of the opening in the

primary, the low decay heat, and the defense in depth available at the time of the

Enclosure

3

event. Based on this, the finding was determined to be of very low safety

significance (Green). The finding has a cross-cutting aspect in the Work

Practices component of the Human Performance cross cutting area, because the

licensee failed to follow plant procedure 0PT-80.1, Reactor Pressure Vessel

(RPV) ASME Section XI Pressure Test during Unit 2 RPV hydrostatic testing.

(H.4(b)). (Section 1R20)

B. Licensee-Identified Violations

None.

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at rated thermal power. Power was reduced to 70 percent

for rod sequence exchange on May 29, 2009, and then returned to rated thermal power on May

31, 2009. Power was reduced to 90 percent for rod improvement on May 31, 2009, and then

returned to rated thermal power. Power was reduced to 94 percent for rod improvement on

June 1, 2009, and then returned to rated thermal power on June 2, 2009, for the remainder of

the inspection period.

Unit 2 began the inspection period shutdown for the planned refueling outage (B219R1). Unit 2

went critical on April 21, 2009. A manual reactor scram was inserted on April 22, 2009, due to

leak associated with the 2A recirculation pump seal. Unit 2 went critical on April 27, 2009 after

maintenance on the 2A recirculation pump seal. Unit 2 synchronized to the grid on

April 29, 2009 and reached rated thermal power on May 1, 2009. Power was reduced to 57

percent on May 23, 2009, for 2A reactor feed pump vibrations and returned to 67 percent power

on May 26, 2009. Power was reduced to 44 percent on May 26 for removal of 4A and 5A feed

water heaters for maintenance. Power was returned to 67 percent power and remained there

until repairs were completed on the 2A reactor feed pump on June 7, 2009. Unit 2 returned to

rated thermal power on June 7, 2009. Power was reduced to 92 percent for rod improvement

on June 8, 2009, and then returned to rated thermal power. Power was again reduced 91.5

percent for rod improvement on June 8, 2009, and then returned to rated thermal power. Power

was reduced to 80 percent due to loss of power to the circulating water ocean discharge pumps

on June 24, 2009, and then returned to rated thermal power for the remainder of the inspection

period.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued

availability of offsite and alternate alternating current (AC) power systems during

adverse weather were appropriate. The inspectors reviewed the licensees procedures

affecting these areas and the communications protocols between the transmission

system operator (TSO) and the plant to verify that the appropriate information was being

exchanged when issues arose that could impact the offsite power system. Examples of

aspects considered in the inspectors review included:

  • The coordination between the TSO and the plant during off-normal or emergency

events;

Enclosure

5

  • The explanations for the events;
  • The estimates of when the offsite power system would be returned to a normal

state; and

  • The notifications from the TSO to the plant when the offsite power system was

returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and

maintain availability and reliability of both the offsite AC power system and the onsite

alternate AC power system prior to or during adverse weather conditions. Specifically,

the inspectors verified that the procedures addressed the following:

  • The actions to be taken when notified by the TSO that the post-trip voltage of the

offsite power system at the plant would not be acceptable to assure the

continued operation of the safety-related loads without transferring to the onsite

power supply;

  • The compensatory actions identified to be performed if it would not be possible to

predict the post-trip voltage at the plant for the current grid conditions;

  • A re-assessment of plant risk based on maintenance activities which could affect

grid reliability, or the ability of the transmission system to provide offsite power;

and

  • The communications between the plant and the TSO when changes at the plant

could impact the transmission system, or when the capability of the transmission

system to provide adequate offsite power was challenged.

Documents reviewed are listed in the Attachment to this report. The inspectors also

reviewed corrective action program items to verify that the licensee was identifying

adverse weather issues at an appropriate threshold and entering them into their

corrective action program in accordance with station corrective action procedures.

b. Findings

No findings of significance were identified.

.2 Summer Seasonal Readiness Preparations

a. Inspection Scope

The inspectors reviewed the licensees preparations for selected systems for severe

weather conditions prior to hurricane season and hot weather.

During the inspection, the inspectors focused on plant specific design features and the

licensees procedures used to mitigate or respond to adverse weather conditions.

Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)

and performance requirements for systems selected for inspection, and verified that

operator actions were appropriate as specified by plant specific procedures. Specific

documents reviewed during this inspection are listed in the Attachment. The inspectors

also reviewed corrective action program items to verify that the licensee was identifying

Enclosure

6

adverse weather issues at an appropriate threshold and entering them into their

corrective action program in accordance with station corrective action procedures. The

inspectors reviews focused specifically on the following plant systems:

y Emergency Diesel Generators

y Service Water

b. Findings

No findings of significance were identified.

.3 Readiness For Impending Adverse Weather Condition

a. Inspection Scope

On April 6, 2009, a tornado warning was issued for the plant area, and inspectors

reviewed the licensees overall preparations/protection for impending adverse weather

conditions. The inspectors walked down areas of the plant susceptible to high winds,

including the licensees emergency alternating current (AC) power systems. The

inspectors evaluated the licensee staffs preparations against the sites procedures and

determined that the staffs actions were adequate. During the inspection, the inspectors

focused on plant-specific design features and the licensees procedures used to respond

to specified adverse weather conditions. The inspectors also toured the plant grounds to

look for any loose debris that could become missiles during a tornado. The inspectors

evaluated operator staffing and accessibility of controls and indications for those

systems required to control the plant. Additionally, the inspectors reviewed the Updated

Final Safety Analysis Report (UFSAR) and performance requirements for systems

selected for inspection, and verified that operator actions were appropriate as specified

by plant specific procedures. Specific documents reviewed during this inspection are

listed in the attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

systems:

  • EDGs #1, 2, 3, and 4 air start lineup on April 6, 2009

inoperable for testing on April 19, 2009

Enclosure

7

  • 2A1 battery charger with the 2A2 battery charger out of service for maintenance

on May 21, 2009.

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

reactor safety cornerstones at the time they were inspected. The inspectors attempted

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

potentially increase risk. The inspectors reviewed applicable operating procedures,

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

Specification (TS) requirements, outstanding work orders, condition reports, and the

impact of ongoing work activities on redundant trains of equipment in order to identify

conditions that could have rendered the systems incapable of performing their intended

functions. The inspectors also walked down accessible portions of the systems to verify

system components and support equipment were aligned correctly and operable. The

inspectors examined the material condition of the components and observed operating

parameters of equipment to verify that there were no obvious deficiencies. The

inspectors also verified that the licensee had properly identified and resolved equipment

alignment problems that could cause initiating events or impact the capability of

mitigating systems or barriers and entered them into the corrective action program with

the appropriate significance characterization. Documents reviewed are listed in the

attachment.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

During the week of June 8, 2009, the inspectors performed a complete system alignment

inspection of Unit 1 and Unit 2 High Pressure Coolant Injection System to verify the

functional capability of the system. This system was selected because it was considered

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

A Review of Operating Experience Smart Sample: OpESS FY2009-02, Negative Trend

and Recurring Events Involving Feedwater Systems was performed. The inspectors

walked down the system to review mechanical and electrical equipment line-ups,

electrical power availability, system pressure and temperature indications, as

appropriate, component labeling, component lubrication, component and equipment

cooling, hangers and supports, operability of support systems, and to ensure that

ancillary equipment or debris did not interfere with equipment operation. A review of a

sample of past and outstanding work orders (WOs) was performed to determine whether

any deficiencies significantly affected the system function. In addition, the inspectors

reviewed the corrective action program (CAP) database to ensure that system

equipment alignment problems were being identified and appropriately resolved. The

documents used for the walkdown and issue review are listed in the attachment.

Enclosure

8

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Quarterly Resident Inspector Tours

a. Inspection Scope

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

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

plant areas:

y Diesel Generator Cell 1 23' Elevation 1PFP-DG-5

y Diesel Generator Cell 2 23' Elevation 1PFP-DG-4

y Diesel Generator Cell 3 23' Elevation 2PFP-DG-3

y Diesel Generator Cell 4 23' Elevation 2PFP-DG-2

y Service Water Building 20' Elevation 0PFP-SW-1a

y Battery Room 2A 23' Elevation 2PFP-CB-9

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

protection program that adequately controlled combustibles and ignition sources within

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

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

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

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

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

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

additional insights, their potential to impact equipment which could initiate or mitigate a

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

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

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

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

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

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

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

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed selected risk-important plant design features and licensee

procedures intended to protect the plant and its safety-related equipment from internal

Enclosure

9

flooding events. The inspectors reviewed flood analyses and design documents,

including the UFSAR, engineering calculations, and abnormal operating procedures

(AOPs), for licensee commitments. The specific documents reviewed are listed in the

attachment. In addition, the inspectors reviewed licensee drawings to identify areas and

equipment that may be affected by internal flooding caused by the failure or

misalignment of nearby sources of water, such as the fire suppression or the circulating

water systems. The inspectors walked down the Radwaste Building, 23 elevation, after

a leak was discovered in the 1B fuel pool cooling filter cubicle on April 8, 2009, to assess

the adequacy of watertight doors and verify drains and sumps were clear of debris and

were operable, and that the licensee complied with its commitments.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (Triennial Review)

a. Inspection Scope

The inspectors reviewed inspection records, test results, maintenance work orders, and

other documentation associated with risk-significant heat exchangers (HXs) and heat

sinks, including components such as outlet piping and the outlet canal, to ensure that

deficiencies that could mask or degrade performance were identified and corrected.

Risk-significant heat exchangers or coolers reviewed included the Residual Heat

Removal (RHR) 1A Heat Exchanger, the RHR 2B Pump Motor Cooler, and the

Emergency Diesel Generator (EDG) #1 Jacket Water Cooler.

The inspectors reviewed the licensees Generic Letter (GL) 89-13 Program procedure,

inspection and cleaning procedures, completed inspection and cleaning records and

results, and design specification sheets for the selected safety-related HXs and coolers,

the intake structure, and the outlet canal and the outlet pumping station. Currently, the

licensee uses an inspection and cleaning program instead of thermal testing for the heat

exchanger and heat sink performance check.

The inspectors also reviewed general health of the Service Water (SW) and Circulating

Water (CW) systems via review of design basis documents, system health reports, self-

assessments, sodium hypochlorite treatment and sampling documents, and discussions

with system engineers. These documents were reviewed to verify that the design bases

were being maintained and to verify adequate SW and CW system performance under

the current licensees regimen of preventive maintenance, which includes chemical

treatment, inspection, physical cleaning, and proceduralized frequencies (which vary due

to conditions).

In addition, the inspectors conducted a walkdown of HXs, coolers, CW and SW piping

systems and pumps, the chemical treatment station, the intake and diversion structures

(observing maintenance and repair activities for the diversion structure), intake and

outlet canals, the outlet pumping station, and other major components to assess general

Enclosure

10

material condition and to identify any degraded conditions of the components. The

inspectors also observed the flow, pressure, and temperature measurements for the

thermal efficiency calculation of EDG #1 Jacket Water Cooler.

Corrective action reports such as Nuclear Condition Reports (NCRs) and Action

Requests (ARs) were reviewed for potential common cause problems and problems

which could affect system performance, to confirm that the licensee was entering

problems into the corrective action program and initiating appropriate corrective actions.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

On June 3, 2009, the inspectors observed a crew of licensed operators in the plants

simulator during licensed operator requalification examinations to verify that operator

performance was adequate, evaluators were identifying and documenting crew

performance problems, and training was being conducted in accordance with licensee

procedures. The inspectors evaluated the following areas:

  • licensed operator performance;
  • crews clarity and formality of communications;
  • ability to take timely actions in the conservative direction;
  • prioritization, interpretation, and verification of annunciator alarms;
  • correct use and implementation of abnormal and emergency procedures;
  • control board manipulations;
  • oversight and direction from supervisors; and
  • ability to identify and implement appropriate TS actions and Emergency Plan

actions and notifications.

The crews performance in these areas was compared to pre-established operator action

expectations and successful critical task completion requirements.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk

significant systems:

Enclosure

11

  • Failure of the pressure reducing valve, 2-DSA-PRV-1689, on EDG #1 on April 8,

2009

  • Failure of EDG #4 to start during testing on April 10, 2009

The inspectors reviewed events where ineffective equipment maintenance has resulted

in invalid automatic actuations of Engineered Safeguards Systems and independently

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

terms of the following:

  • implementing appropriate work practices;
  • identifying and addressing common cause failures;
  • scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
  • characterizing system reliability issues for performance;
  • charging unavailability for performance;
  • trending key parameters for condition monitoring;
  • verifying appropriate performance criteria for structures, systems, and

components (SSCs)/functions classified as (a)(2) or appropriate and adequate

goals and corrective actions for systems classified as (a)(1).

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

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

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

significance characterization. Documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

five maintenance and emergent work activities affecting risk-significant equipment listed

below to verify that the appropriate risk assessments were performed prior to removing

equipment for work:

  • EDG #4 testing with plant in Yellow risk on April 8, 2009.
  • Comprehensive review of the maintenance planned and conducted during the

Unit 2 refueling outage during the week of April 26, 2009.

  • Battery charger 2A2 and the 2A nuclear service water pump out of service on

May 21, 2009.

  • EDG #1 and the 2A main feed pump out of service on June 2, 2009.
  • Unit 1 condensate storage tank returned to service and realignment of HPCI and

RCIC suction during week of June 15, 2009.

Enclosure

12

These activities were selected based on their potential risk significance relative to the

reactor safety cornerstones. As applicable for each activity, the inspectors verified that

risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate

and complete. When emergent work was performed, the inspectors verified that the

plant risk was promptly reassessed and managed. The inspectors reviewed the scope

of maintenance work, discussed the results of the assessment with the licensee's

probabilistic risk analyst or shift technical advisor, and verified plant conditions were

consistent with the risk assessment. The inspectors also reviewed TS requirements and

walked down portions of redundant safety systems, when applicable, to verify risk

analysis assumptions were valid and applicable requirements were met.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

  • EDG #1 degraded air start header on April 5, 2009
  • EDG #3 with degraded four-day storage tank level indication on April 7, 2009

discovered on April 10, 2009

  • 2B RHRSW pump was found with low oil level on April 23, 2009

accumulator test connection on May 7, 2009

  • Diesel Generator service water discharge line out of round on June 8, 2009

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

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

adequacy of the evaluations to ensure that TS operability was properly justified and the

subject component or system remained available such that no unrecognized increase in

risk occurred. The inspectors compared the operability and design criteria in the

appropriate sections of the Technical Specifications (TS) and Updated Final Safety

Analysis Report (UFSAR) to the licensees evaluations, to determine whether the

components or systems were operable. Where compensatory measures were required

to maintain operability, the inspectors determined whether the measures in place would

function as intended and were properly controlled. The inspectors determined, where

appropriate, compliance with bounding limitations associated with the evaluations.

Additionally, the inspectors also reviewed a sampling of corrective action documents to

verify that the licensee was identifying and correcting any deficiencies associated with

operability evaluations. Documents reviewed are listed in the attachment.

Enclosure

13

b. Findings

No findings of significance were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following eight post-maintenance (PM) activities to verify

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

functional capability:

(conventional service water) pump seal leakage maintenance on April 4, 2009

maintenance on the auxiliary switch functions of the RHR pump and EDG output

breakers on April 4, 2009

after secondary containment maintenance

  • 0PT-12.2C, No. 3 Diesel Generator Monthly Load Test on April 5, 2009 after

maintenance on the starting air distributor

2009 after maintenance on room cooler only

  • 0PT-12.2A, No. 1 Diesel Generator Monthly Load Test on April 9, 2009 after

maintenance on the diesel engine starting air tank pressure-reducing valve

April 9, 2009

  • 0PT-12.2D, No. 4 Diesel Generator Monthly Load Test on April 10, 2009 after

maintenance on the fuel rack limit cylinder and mechanical governor

These activities were selected based upon the structure, system, or component's ability

to impact risk. The inspectors evaluated these activities for the following: the effect of

testing on the plant had been adequately addressed; testing was adequate for the

maintenance performed; acceptance criteria were clear and demonstrated operational

readiness; test instrumentation was appropriate; tests were performed as written in

accordance with properly reviewed and approved procedures; equipment was returned

to its operational status following testing, and test documentation was properly

evaluated. The inspectors evaluated the activities against TS and the UFSAR to ensure

that the test results adequately ensured that the equipment met the licensing basis and

design requirements. In addition, the inspectors reviewed corrective action documents

associated with post-maintenance tests to determine whether the licensee was

identifying problems and entering them in the corrective action program and that the

problems were being corrected commensurate with their importance to safety.

Documents reviewed are listed in the attachment.

Enclosure

14

b. Findings

No findings of significance were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

Unit 2 continued in a refueling outage at the beginning of the inspection period. During

this inspection period, the inspectors monitored licensee controls over the outage

activities listed below. Documents reviewed during the inspection are listed in the

attachment.

  • Licensee configuration management, including maintenance of defense-in-depth

commensurate with the OSP for key safety functions and compliance with the

applicable TS when taking equipment out of service

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

instruments to provide accurate indications, accounting for instrument error

  • Controls over the status and configuration of electrical systems to ensure that TS

and outage safety plan requirements were met, and controls over switchyard

activities

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

to operate the spent fuel pool cooling system

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

  • Controls over activities that could affect reactivity
  • Refueling activities, including fuel handling and sipping to detect fuel assembly

leakage

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

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

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

reactor physics testing

  • Licensee identification and resolution of problems related to refueling outage

activities

b. Findings

Failure to Follow Plant Procedures During Performance of a Reactor Pressure Vessel

Hydrostatic Test

Introduction. A self revealing Green NCV of TS 5.4.1.a, Administrative Control

(Procedures), was identified when the licensee failed to follow plant procedure 0PT-80.1,

Reactor Pressure Vessel (RPV) ASME Section XI Pressure Test during Unit 2 RPV

Enclosure

15

hydrostatic testing on April 7, 2009. The licensee installed hoses rated for 250 psig

although the procedure required hoses rated at 1150 psig. Specifically, when RPV

pressure was raised to approximately 1000 psig, the improper hose installed at core

spray check valve 2-E21-F006B disconnected from its coupling, causing the RPV to

rapidly depressurize to approximately 875 psig and allowing water from the RPV to leak

out of the connection into the drywell.

Description. On April 7, 2009, Unit 2 was in Mode 4 during refueling outage 2B19R1.

During preparations for performing procedure 0PT-80.1, Reactor Pressure Vessel (RPV)

ASME Section XI Pressure Test, hoses were installed around the core spray system

injection line check valves. These hoses are installed around the check valves in order

to pressurize portions of the core spray system upstream of the check valves during the

test. 0PT-80.1 specifies that RPV pressure be between 1050 psig and 1070 psig, and

that the hoses used to bypass the core spray system injection line check valves be rated

for at least 1150 psig. However, the hoses installed around the check valves were only

rated to 250 psig. These hoses were used because they were stored in a bag that was

labeled CS Jumper 0PT-80.1/20.7B, and licensee personnel assumed they were the

correct hoses without verification of the hoses pressure ratings. After RPV pressure

was raised to 1045 psig, personnel in the drywell noted water coming from the upper

level of the drywell (the exact amount of water was not quantified, but the drywell sump

filled and approximately one inch of water accumulated on the lowest drywell level floor).

Control room operators also noted a rapid drop in RPV pressure. Upon investigation,

licensee personnel in the drywell discovered the broken hose connection, and isolated

the leak.

Analysis. The inspectors determined that the failure to follow the requirements of

procedure 0PT-80.1, Reactor Pressure Vessel (RPV) ASME Section XI Pressure Test,

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

because the finding was associated with the Initiating Events cornerstone attribute of

human performance and affected the cornerstone objective of limiting the likelihood of

those events that upset plant stability and challenge critical safety functions during

shutdown as well as power operations. Specifically, when RPV pressure was raised to

approximately 1000 psig, the improper hose installed at core spray check valve 2-E21-

F006B disconnected from its coupling, causing the RPV to rapidly depressurize to

approximately 875 psig and allowing water from the RPV to leak out of the connection

into the drywell. The inspectors determined that the finding should be evaluated in

accordance with Attachment 1 of IMC 0609, Appendix G, Shutdown Operations SDP.

The inspectors used Checklist 8 contained in Attachment 1 and determined that the

finding did require a phase 2 or phase 3 because the licensee did not meet the

appropriate safety function guidelines for inventory control. Specifically, the finding

increases the likelihood of a loss of RCS inventory. The regional Senior Reactor Analyst

(SRA) determined, after a teleconference with the headquarters SRA with responsibility

for Shutdown findings, that the event did not rise to a level that would require a detailed

analysis be performed. The event did not meet the threshold for a loss of control as

defined by Appendix G. Additional margin was provided by the high elevation of the leak

relative to the top of active fuel, and the suction head requirement of the residual heat

removal (RHR) system, the small size of the opening in the primary, the low decay heat,

Enclosure

16

and the defense in depth available at the time of the event. Based on this, the finding

was determined to be of very low safety significance (Green).

The finding has a cross-cutting aspect in the Work Practices component of the Human

Performance cross cutting area, because the licensee failed to follow plant procedure

0PT-80.1, Reactor Pressure Vessel (RPV) ASME Section XI Pressure Test during Unit 2

RPV hydrostatic testing. (H.4(b)).

Enforcement. Technical Specification Section 5.4.1.a, Administrative Control

(Procedures), states, in part, that written procedures shall be established, implemented,

and maintained, covering applicable procedures recommended in Regulatory Guide

1.33, Appendix A, November 1972 (Safety Guide 33, November 1972). Section l.1 of

Regulatory Guide 1.33, Appendix A, November 1972, (Safety Guide 33,

November 1972) states, in part, that maintenance that can affect the performance of

safety-related equipment should be properly planned and performed in accordance with

written procedures, documented instructions, or drawings appropriate to the

circumstances. The licensee established OPT-80.1, Reactor Pressure Vessel (RPV)

ASME Section XI, Pressure Test, as the implementing procedure for the hydrostatic test.

Contrary to the above, on April 7, 2009, the licensee failed to follow procedure 0PT-80.1,

Reactor Pressure Vessel (RPV) ASME Section XI Pressure Test. Step 5.1.1 requires

installation of hoses with a pressure rating of at least 1150 psig. Specifically, the

licensee installed hoses rated at 250 psig, instead of the required hoses. As a result of

this maintenance error, the RPV depressurized and RPV water leaked into the drywell.

The licensee discovered the leak and broken hose connection, isolated the leak, and

initiated AR329675329675to address this issue. Because this violation was of very low safety

significance and it was entered into the licensees CAP (AR 329675329675, this violation is

being treated as an NCV, consistent with the NRC Enforcement Policy. This violation is

therefore designated as NCV 05000324/2009003-01, Failure to Follow Plant Procedures

During Performance of a Reactor Pressure Vessel Hydrostatic Test.

1R22 Surveillance Testing

.1 Routine Surveillance Testing

a. Inspection Scope

The inspectors either observed surveillance tests or reviewed the test results for the

following four activities to verify the tests met TS surveillance requirements, UFSAR

commitments, inservice testing 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.

Pressure Functional Test for EDG #3 on April 4, 2009

Enclosure

17

  • 0PT12.18L, Unit Substation E7 Local Control Operability Test on April 6, 2009
  • 0PT-13.1, Unit 1 Reactor Recirculation Jet Pump Operability on April 7, 2009

b. Findings

No findings of significance were identified.

.2 Inservice Testing (IST) Surveillance

a. Inspection Scope

The inspectors reviewed the performance of 0PT-10.1.1, RCIC System Operability Test

on June 24, 2009, to evaluate the effectiveness of the licensees American Society of

Mechanical Engineers (ASME)Section XI testing program for determining 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.

b. Findings

No findings of significance were identified.

.3 Reactor Coolant System Leak Detection Inspection Surveillance

a. Inspection Scope

The inspectors observed and reviewed the test results for a reactor coolant system leak

detection surveillance, 0PT-80.1, Reactor Pressure Vessel ASME Section XXI Pressure

Test on April 8, 2009. The inspectors observed plant activities and reviewed procedures

and associated records to determine whether: effects of the testing were adequately

addressed by control room personnel or engineers prior to the commencement of the

testing; acceptance criteria were clearly stated, demonstrated operational readiness, and

were consistent with the system design basis; plant equipment calibration was correct,

accurate, and properly documented; and the calibration frequency were in accordance

with TSs, the UFSAR, procedures, and applicable commitments; applicable

prerequisites described in the test procedures were satisfied; test frequencies met TS

requirements to demonstrate operability and reliability; tests were performed in

accordance with the test procedures and other applicable procedures; test data and

results were accurate, complete, within limits, and valid; equipment was returned to a

position or status required to support the performance of its safety functions; and all

problems identified during the testing were appropriately documented and dispositioned

in the corrective action program. Documents reviewed are listed in the attachment.

Enclosure

18

b. Findings

No findings of significance were identified.

1EP6 Emergency Planning Drill Evaluation

a. Inspection Scope

The inspectors observed two site emergency preparedness training drill/simulator

scenarios conducted on June 9 and June 24, 2009. The inspectors reviewed the drill

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

protective action recommendations development activities. During the drill, the

inspectors assessed the adequacy of event classification and notification activities. The

inspectors observed portions of the licensees post-drill. 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.

b. Findings

No findings of significance were identified.

4. OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

To verify the accuracy of the PI data reported to the NRC, the inspectors compared the

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

contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment

Indicator Guideline.

Mitigating Systems Cornerstone

y Mitigating Systems Performance Index, Emergency AC Power

y Mitigating Systems Performance Index, Cooling Water Systems

The inspectors sampled licensee submittals for the Mitigating Systems Performance

Index performance indicators listed above for the period from the second quarter of 2008

through the first quarter of 2009. The inspectors reviewed the licensees operator

narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated

Inspection reports for the period to validate the accuracy of the submittals. The

inspectors reviewed the MSPI component risk coefficient to determine if it had changed

by more than 25 percent in value since the previous inspection, and if so, that the

change was in accordance with applicable NEI guidance. The inspectors also reviewed

the licensees issue report database to determine if any problems had been identified

Enclosure

19

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

Specific documents reviewed are described in the Appendix to this report.

y Safety System Functional Failures

The inspectors reviewed licensee submittals for the Safety System Functional Failures

performance indicator for the period from the second quarter of 2008 through the first

quarter of 2009. The inspectors reviewed the licensees operator narrative logs,

operability assessments, maintenance rule records, maintenance work orders, issue

reports, event reports and NRC Integrated Inspection reports for the period to validate

the accuracy of the submittals. Specific documents reviewed are described in the

Appendix to this report.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered Into the Corrective Action Program

a. Scope

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

issues for follow-up, the inspectors performed frequent screenings of items entered into

the licensees corrective action program. The review was accomplished by reviewing

daily action request reports.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Trend Review

a. 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

inspectors review was focused on repetitive equipment issues, but also considered the

results of daily inspector CAP item screening discussed in Section 4OA2.1 above,

licensee trending efforts, and licensee human performance results. The inspectors

review nominally considered the six-month period of January 2009 through June 2009,

although some examples expanded beyond those dates where the scope of the trend

warranted.

The review also included issues documented outside the normal CAP in major

equipment problem lists, repetitive and/or rework maintenance lists, departmental

problem/challenges lists, system health reports, quality assurance audit/surveillance

Enclosure

20

reports, self assessment reports, and Maintenance Rule assessments. The inspectors

compared and contrasted their results with the results contained in the licensees CAP

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

the licensees trending reports were reviewed for adequacy.

b. Assessment and Observations

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

adherence and the work management process. In particular, adverse effects

had been identified on system performance. This was exemplified by the following

identified issues:

y Improper loosening of RPV reference leg connection, NCR# 322354

y Unit 2 interruption of Shutdown Cooling due to maintenance, NCR# 327475

y Rx Hydro core spray check valve high pressure test jumper failure, NCR#

329677

y Work accomplished with inadequate documentation, NCR# 330266

y Improperly performed procedure step during 0MST-PCIS41R, NCR# 331004

The inspectors concluded that while the licensee has been providing additional focus

and training to this area, more attention and follow-up is needed.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period the inspectors conducted observations of security force

personnel and activities to ensure that the activities were consistent with licensee

security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities

did not constitute any additional inspection samples. Rather, they were considered an

integral part of the inspectors' normal plant status reviews and inspection activities.

b. Findings

No findings of significance were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On July 16, 2009 the inspector presented the inspection results to Mr. Ben Waldrep and

other members of the licensee staff. The inspectors confirmed that proprietary

information was not provided or examined during the inspection period.

Enclosure

21

An exit meeting for the Heat Sink inspection was conducted on June 5, 2009 with

licensee management.

ATTACHMENT: SUPPLEMENTAL INFORMATION

Enclosure

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

M. Annacone, Director Site Operations

G. Atkinson, Supervisor - Licensing and Regulatory Affairs

L. Beller, Superintendent, Operations Training

M. Blew, Engineering

B. Brewer, Manager- Maintenance

A. Brittain, Manager - Security

B. Davis, Manager - Engineering

P. Dubrouillet, Supervisor - Plant Support Group

S. Gordy, Manager - Operations

L. Grzeck, Lead Engineer - Technical Support

K. Hamm, Intake and Circulating Water System Engineer

E. Harkcom, Service Water System Engineer

S. Howard, Manager - Outage and Scheduling

R. Ivey, Manager - Nuclear Oversight Section

J. Johnson, Manager - Environmental and Radiological Controls

S. Larson, ISI Coordinator

P. Mentel, Manager - Nuclear Support Services

W. Murray, Licensing Specialist

A. Pope, Manager - Station Recovery

T. Sherrill, Engineer - Technical Support

G. Spry, Welding Engineer

J. Titrington, Superintendent - Design Engineering

M. Turkal, Lead Engineer - Technical Support

J. Vincelli, Superintendent - Environmental and Radiological Controls

B. Waldrep, Site Vice President

M. Williams, Manager - Training Manager

E. Wills, Plant General Manager

B. Wilton, Engineering

NRC Personnel

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

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000324/2009003-01 NCV Failure to Follow Plant Procedures During

Performance of a Reactor Pressure Vessel

Hydrostatic Test (Section 1R20)

Attachment

LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

0AOP-13.0, Operation during Hurricane, Flood Conditions, Tornado, or Earthquake

0A1-68, Brunswick Nuclear Plant Response to Severe Weather Warnings

0PEP-02.1, Initial Emergency Actions

0PEP-02.6, Severe Weather

0O1-01.03, Non-Routine Activities

Section 1R04: Equipment Alignment

0OP-50.1, Diesel Generator Emergency Power System Operating Procedure

Drawing D-02265, sheets 1A and 1B, drawing D-02266, sheets 2A and 2B, Piping Diagram for

Diesel Generators Starting Air System Units 1 and 2

Drawing D-02268, sheets 1A and 1B, drawing D-02269, sheets 2A and 2B, Piping Diagram for

Diesel Generators Fuel Oil System Units 1 and 2

Drawing D-02270, sheets 1A and 1B, drawing D-02271, sheets 2A and 2B, Piping Diagram for

Diesel Generators Lube Oil to Lube Oil System Units 1 and 2

Drawing D-02272, sheets 1A and 1B, drawing D-02273, sheets 2A and 2B, Piping Diagram for

Diesel Generators Jacket Water System Units 1 and 2

Drawing D-02272, sheets 1A and 1B, drawing D-02273, sheets 2A and 2B, Piping Diagram for

Diesel Generators Jacket Water System Units 1 and 2

Drawing D-02274, sheets 1 and 2, Piping Diagram for Diesel Generators Service and

Demineralized Water System Units 1 and 2

1OP-16, Reactor Core Isolation Cooling System Operating Procedure

2OP-16, Reactor Core Isolation Cooling System Operating Procedure

1OP-19, High Pressure Cooling Injection System Operating Procedure

2OP-19, High Pressure Cooling Injection System Operating Procedure

Section 1R05: Fire Protection

0PFP-CB, Control Building Prefire Plans

0PFP-DG, Diesel Generator Building Prefire Plans

0PFP-PBAA, Power Block Auxiliary Areas Prefire Plans SW, RW, AOG, TY, EY

0PFP-013, General Fire Plan

1PFP-RB, Reactor Building Prefire Plans Unit 1

1PFP-TB, Turbine Building Prefire Plans Unit 1

2PFP-RB, Reactor Building Prefire Plans Unit 2

2PFP-TB, Turbine Building Prefire Plans Unit 2

0OP-41, Fire Protection and Well Water System

0PFP-MBPA, Miscellaneous Buildings Pre-Fire Plans - Protected Area

0PT-34.11.2.0, Portable Fire Extinguisher Inspection

Section 1R07: Heat Sink Performance

Procedures

EGR-NGGC-0008, Rev. 3, Engineering Program

OPM-ACU 500, Rev. 7, Inspection and Cleaning of the RHR/CORE Spray Room Aerofin Cooler

Air Filters and Coolers EPEG 02-04, Rev. 0, Service Water Reliability - Generic Letter 89-13

Program

TG-ESG 507B, Rev. 0, Cooling Water Reliability GL 89-13 Program Manager Training Guide

Attachment

3

OENP-303, Rev. 7, RHR and Core Spray Room Cooler Performance

OENP-2704, Rev. 17, Administrative Control of NRC Generic Letter 89-13 Requirements

OPM-STU 501, Rev. 11, Circulating Water Intake Structure Silt Removal

Administrative Instruction (0AI)-81, Rev. 51, Water Chemistry Guidelines

0AI-82, Rev. 3, Closed Cooling Water Chemistry Guidelines

0AI-146, Rev. 1, Plant Response to Degraded Conditions at the Intake Structure

Environmental and Radiation Control (0E&RC)-3295, Rev. 22, Canal Monitoring

OPM-STU500, Rev. 18, Service Water Intake Structure Inspection and Cleaning

Calculations

OSW-0097, Rev. 0, RHR and Core Spray Room Cooler Performance

OSW-0096, Rev. 0, Calculation for Tube Plugging of Service Water Safety Related Heat

Exchangers

G0050A-04, Rev. 1, Design Basis Heat Loads from Vital Heat Exchangers

G0050A-16, Rev. 1, Service Water Single Failure Analysis

Corrective Action Documents - Nonconforming Report (NCR) or Action Reports (ARs)

NCR 249130, the Differential Pressure across the RHR 1A Heat Exchanger Was Measured at

200 Inches of Water

NCR 224737, A Significant Growth of Oyster Shells and Barnacles was Observed on the 24

Header That Supplies Conventional Service Water to the A Loop RHR SW Vital Header

Action Request (AR) 00247053, Shells in 1A RHR Room Cooler & Inlet Piping

AR 00271611, Adverse Trend in BNP Service Water Performance

  • AR 00339272, Inadequate Equation Use for Calculating Heat Exchanger Efficiency

AR 00315056, Incorporate Inspection of Concrete Surfaces and Enhance the Structural

Inspection of the CW Intake Structure

  • Documents created as a direct result of this inspection.

Other

Work Order (WO) 1121279 for Procedure OENP-2704, Service Water Safety Related Heat

Exchanger Cleaning/Inspection Data Sheet for 1A RHR Heat Exchanger, Dated April 5, 2008

WO 1121279-07, Ultrasonic Examination (UT) Inspection on Flange on RHR 1A Heat

Exchanger, Dated February 15, 2008

WO 1130955-01, Drain and Clean Tubes on RHR 1A Heat Exchanger, Dated October 4, 2007

WO 737124 (Procedure OENP-2704), Service Water Safety Related Heat Exchanger

Cleaning/Inspection Data Sheet for 2B RHR SW Pump Motor Cooler, Dated February 21, 2007

WO 1318238-1 (Procedure OENP-2704), Service Water Safety Related Heat Exchanger

Cleaning/Inspection Data Sheet for 2B RHR SW Pump Motor Cooler, Dated April 11, 2008

WO 1318238, Boroscope the #1 EDG Jacket Water Cooler, Dated April 11, 2008

System Health Report for System #4060, Service Water

Chlorine Residual Rate Measurements - Sample points, Analysis, and Sample dates from

March 1 to May 31, 2009

NGG Program Health Report for Cooling Water Reliability (89-13), Dated January 8, 2009

Service Water Trash Rack Monthly Inspection and Cleaning in March, April, and May, 2009

Attachment

4

Bi-Weekly Diversion Structure Inspection for Service Water Intake in March, April, and May,

2009

WO 01360507, Monthly Units Circulating Water Intake Trash Rack Inspection Cleaning, May

2009

WO 00973437, Yearly Unit 2 SW and SCW Pump Bay Silt and Biofouling Inspection and

Cleaning, February 2008

Service Water Safety Related Heat Exchanger Cleaning/Inspection Data Sheet for EDG #1

Jacket Water Cooler Flow Test, June 4, 2009

Flow Test Results for RHR 2B Heat Exchanger Dated April 8, 2007

Preliminary Eddy Current Inspection Report for Unit 2 Residual Heat Removal (RHR) Heat

Exchanger (Hx) 2B, dated March 9, 2009

Control Chart for differential pressure ( P) across the 1A RHR Hx since Spring 2002

Control Chart for temperature (T) across the # 2 Emergency Diesel Generator HX since

Spring 2008

Cooling Water System (89-13) Health Report, dated January 8, 2009

Cooling Water System (89-13) Health Report, dated July 24, 2008

WO 00647095-09, Perform HX Flow Test on the 2-MUD-JKT-WTR-CLR-1

Section 1R11: Licensed Operator Requalification

0TPP, Licensed Operator Continuing Training Program

TRN-NGGC-0014, NRC Initial Licensed Operator Exam Development and Administration

1EOP-01-LPC, Level/Power Control

0PEP-2.1.1, Emergency Control - Notification of Unusual Event, Alert, Site Area Emergency, or

General Emergency

0PEP-02.1, Initial Emergency Actions

Section 1R12: Maintenance Effectiveness

ADM-NGGC-0101, Maintenance Rule Program

NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear

Power Plants

ADM-NGGC-0203, Preventive Maintenance and Surveillance Testing

Administration

EGR-NGGC-0351, Condition Monitoring of Structures

ADM-NGGC-0203, Preventive Maintenance and Surveillance test Administration

0AP-022, BNP Outage Risk Management

NCR #329679, 2-DSA-PRV-1689 Failed Pmt

NRC #330193, Unexpected Trip of EDG#4

Section 1R13: Maintenance Risk Assessment and Emergent Work Control

0AP-022, BNP Outage Risk Management

ADM-NGCC-0104, Work Management Process

0AI-144, Risk Management

ADM-NGGC-0006, Online EOOS Model

Attachment

5

Section 1R15: Operability Evaluations

OPS-NGGC-1305, Operability Determinations

OPS-NGGC-1307, Operational Decision making

NCR# 329545, EDG # 3 four day tank level indication

Section 1R18: Plant Modifications

EGR-NGGC-0005, Engineering Change

EGR-NGGC-0011, Engineering Product Quality

0SMP-MO003, Soft Electrical Backseating of AC Motor Operated Valves Using the Motor

Operator

Section 1R19: Post Maintenance Testing

0PLP-20, Post Maintenance Testing Program

Section 1R20: Outage Activities

1OP17, Residual Heat Removal System Operating Procedure

0GP-01, Prestartup Checklist

0GP-02, Approach to Criticality and Pressurization of the Reactor

0GP-03, Unit Startup and Synchronization

0GP-12, Power Changes

0SMP-RPV502, Reactor Vessel Reassembly

0MMM-015, Operation and Inspection of Cranes and Material Handing Equipment

Section 4OA1: Performance Indicator Verification

Procedures

REG-NGGC-0009, NRC Performance Indicators and Monthly Operating Report Data

Records and Data

Monthly PI Reports, September 2007 - August 2008

Attachment

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