ML12312A082

IR 05000325-12-004, 05000324-12-004; 07/01/12 - 09/30/12; Brunswick Steam Electric Plant, Units 1 & 2; Refueling and Other Outage Activities, Identification and Resolution of Problems

ML12312A082
Person / Time
Site:	Brunswick
Issue date:	11/07/2012
From:	Musser R A NRC/RGN-II/DRP/RPB4
To:	Annacone M J Carolina Power & Light Co
Shared Package
ML12325A266	List: IR 05000324/2012004 ML12312A082
References
IR-12-004
Download: ML12312A082 (45)

See also: IR 05000324/2012004

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II 245 PEACHTREE CENTER AVENUE NE, SUITE 1200 ATLANTA, GEORGIA 30303-1257

November 7, 2012

Mr. Michael J. Annacone Vice President

Brunswick Steam Electric Plant P.O. Box 10429 Southport, NC 28461-0429

SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2012004 AND 05000324/2012004

Dear Mr. Annacone:

On September 30, 2012, the U.S. 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 October 11, 2012, 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 Commission's rules and regulations and with the conditions of your license.

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

personnel.

One NRC-identified and one self-revealing finding of very low safety significance (Green) were

identified during this inspection.

These findings were determ

ined to involve a violation of NRC requirements. Further, two licensee-identified violations were determined to be of very low

safety significance and are listed in this report. The NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violations or the significance of these NCVs, 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.

If you disagree with the cross-cutting aspect assignment 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.

M. Annacone 2

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

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

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

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, 324/2012004

w/Attachment: Supplemental Information

cc w/encl: (See page 3)

ML12312A082_________________ x SUNSI REVIEW COMPLETE x FORM 665 ATTACHED OFFICE RII:DRP RII:DRP RII:DRP RII:DRP RII:DRP RII:DRP RII:DRP SIGNATURE JSD: /RA/ RAM RA for

MPS Via e-mail Via e-mail Via e-mail Via e-mail JGW: /RA/ NAME JDodson MCatts MSchwieg PNiebaum LLake MEndress JWorosilo DATE 10/24/2012 11/07/2012 10/24/2012 10/29/2012 10/26/2012 10/25/2012 10/15/2012 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO OFFICE RII:DRP RII:DRS SIGNATURE RAM: /RA/ Via e-mail NAME RMusser MSpeck DATE 11/7/2012 11/06/2012 E-MAIL COPY? YES NO YES NO

M. Annacone 3

cc w/encl:

Plant General Manager

Brunswick Steam Electric Plant

Progress Energy

Electronic Mail Distribution

Edward L. Wills, Jr.

Director Site Operations

Brunswick Steam Electric Plant

Electronic Mail Distribution

J. W. (Bill) Pitesa

Senior Vice President

Nuclear Operations

Duke Energy Corporation

Electronic Mail Distribution

John A. Krakuszeski

Plant Manager

Brunswick Steam Electric Plant

Electronic Mail Distribution

Lara S. Nichols

Deputy General Counsel

Duke Energy Corporation

Electronic Mail Distribution

M. Christopher Nolan

Director - Regulatory Affairs

General Office

Duke Energy Corporation

Electronic Mail Distribution

Michael J. Annacone

Vice President

Brunswick Steam Electric Plant

Electronic Mail Distribution

Annette H. Pope

Manager-Organizational Effectiveness

Brunswick Steam Electric Plant

Electronic Mail Distribution

Lee Grzeck

Regulatory Affairs Manager

Brunswick Steam Electric Plant

Progress Energy Carolinas, Inc.

Electronic Mail Distribution

Randy C. Ivey

Manager, Nuclear Oversight

Brunswick Steam Electric Plant

Progress Energy Carolinas, Inc. Electronic Mail Distribution

Paul E. Dubrouillet

Manager, Training

Brunswick Steam Electric Plant

Electronic Mail Distribution

Joseph W. Donahue

Vice President

Nuclear Oversight

Progress Energy Electronic Mail Distribution

Senior Resident Inspector

U.S. Nuclear Regulatory Commission

Brunswick Steam Electric Plant U.S. NRC 8470 River Road, SE

Southport, NC 28461

John H. O'Neill, Jr.

Shaw, Pittman, Potts & Trowbridge

2300 N. Street, NW Washington, DC 20037-1128

Peggy Force

Assistant Attorney General

State of North Carolina P.O. Box 629

Raleigh, NC 27602

(cc w/encl - continued)

M. Annacone 4

cc w/encl cont'd:

Chairman

North Carolina Utilities Commission

Electronic Mail Distribution

Robert P. Gruber Executive Director

Public Staff - NCUC

4326 Mail Service Center

Raleigh, NC 27699-4326

Anthony Marzano

Director

Brunswick County Emergency Services

Electronic Mail Distribution

Public Service Commission

State of South Carolina

P.O. Box 11649

Columbia, SC 29211

W. Lee Cox, III Section Chief

Radiation Protection Section

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

M. Annacone 5

Letter to Michael J. Annacone from Randall A. Musser dated November 7, 2012

SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2012004 AND 05000324/2012004

Distribution w/encl:

J. Baptist, RII EICS

L. Douglas, RII EICS

OE Mail (email address if applicable)

RIDSNRRDIRS PUBLIC R. Pascarelli, NRR ((Regulatory Conferences Only))

RidsNrrPMBrunswick Resource

Enclosure U. S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos.: 50-325, 50-324

License Nos.: DPR-71, DPR-62

Report Nos.: 05000325/2012004, 05000324/2012004

Licensee: Carolina Power and Light (CP&L)

Facility: Brunswick Steam Electric Plant, Units 1 & 2

Location: 8470 River Road, SE Southport, NC 28461

Dates: July 1, 2012 through September 30, 2012

Inspectors: M. Catts, Senior Resident Inspector M. Schwieg, Resident Inspector

P. Niebaum, Acting Senior Resident Inspector

J. Dodson, Senior Project Engineer (1R04, 1R05, 4OA2)

L. Lake, Senior Reactor Inspector (4OA5)

M. Endress, Reactor Inspector (1R07)

Approved by: Randall A. Musser, Chief Reactor Projects Branch 4

Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000325/2012004, 05000324/2012004; 07/01/12 - 09/30/12; Brunswick Steam Electric

Plant, Units 1 & 2; Refueling and Other Outage Activities, Identification and Resolution of

Problems

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were 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 aspects were determined using IMC 0310, "Components Within the

Cross-Cutting Areas". 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: Barrier Integrity

Green: The inspectors identified a Green non-cited violation (NCV) of TS 3.6.4.1, Secondary Containment because the licensee did not maintain secondary containment

operable as required during a maintenance activity considered an operation with a

potential for draining the reactor vessel (OPDRV). Once questioned by the inspectors,

the licensee restored secondary containment, developed an Operation standing instruction (12-052) to treat the activity as an OPDRV and placed this issue into its corrective action program (CAP) as AR 562188562188 The failure to maintain secondary containment operable while Unit 1 was in Mode 4 with an OPDRV in progress was a performance deficiency. The finding was more than minor because it was associated with the configuration control attribute of the Barrier Integrity

Cornerstone, and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and

containment) protect the public from radionuclide releases caused by accidents or

events because the Unit 1 secondary containment boundary was not preserved or maintained. The inspectors evaluated the finding using Inspection Manual Chapter (IMC) 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings,

which required an analysis using IMC 0609 Appendix G since the reactor was in Mode 4 (cold shutdown). The finding was determined to be of very low safety significance

(Green) according to IMC 0609 Appendix G, Attachment 1, Checklist 6, since a quantitative assessment (Phase 2 or Phase 3 evaluation) was not required. Specifically, the inspectors determined that the licensee maintained adequate mitigation capability for

reactor vessel water level inventory and an event did not occur that could be

characterized as a loss of control. The cause of this finding was directly related to the

cross-cutting aspect of Accurate Procedures in the Resources component of the Human

Performance area, because the licensee did not consider the recirculation pump seal replacement activity to be OPDRV based on procedural guidance that contains exclusions to what are considered OPDRV activities. H.2(c) (Section 1R20)

3 Cornerstone: Emergency Preparedness

Green: A self-revealing Green NCV of 10 CFR 50.54(q)(2) was identified for the licensee's failure to properly evaluate or consider the impact to emergency response

facilities of design change ESR98-00436 which was implemented in 1999. This resulted

in the loss of Emergency Response Facility Information System (ERFIS), Emergency Response Data System (ERDS), Safety

Parameter Display System (SPDS), and all displays including radiation monitors for the emergency response facilities. Specifically, the licensee failed to ensure that adequate emergency response facilities and equipment

were available as required by the Brunswick Nuclear Plant Radiological Emergency

Plan, Section 1.3.1.3 revision 80 and 10 CFR 50.47(b)(8). This issue was captured in the

licensee's CAP as AR 542704542704

The licensee's failure to properly evaluate or consider the impact to emergency

response facilities of design change ESR98-00436 which was implemented in 1999 was

a performance deficiency. Specifically, the licensee introduced a single point failure

mode which did not meet the design requirements specified in their Design Basis Document (DBD 60) sections 3.6.7.2 and 3.6.7.3. This resulted in the licensee's failure to ensure that adequate emergency response facilities and equipment were available as

delineated in the Updated Final Safety Analysis Report (UFSAR) Section 7.7.1.9, and

required by the Brunswick Nuclear Plant Radiological Emergency Plan, Section 1.3.1.3,

revision 80, and 10 CFR 50.47(b)(8). The finding was more than minor because it

adversely affected the Emergency Preparedness Cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the Facilities and Equipment attribute was affected during the time when the ERFIS, ERDS, SPDS,

and all displays including radiation monitors for the emergency response facilities were degraded, and as a result did not meet 10 CFR 50.47(b)(8) Planning Standard program element, adequate emergency facilities and equipment to support the emergency response are provided and maintained. The finding was assessed for significance in

accordance with NRC IMC 0609, Appendix B Emergency Preparedness Significance

Determination Process. Attachment 2 of Appendix B, Failure to Comply Significance

Logic is as follows: Failure to comply; Loss of Risk Significant Planning Standard

Function (RSPS), No; RSPS Degraded Function, No; Loss of Planning Standard Function, No; the result is a Green finding. The inspectors determined that this resulted in a very low safety significance finding (Green). No cross-cutting aspect was assigned

to this finding because the performance deficiency occurred more than three years ago and is not reflective of current plant performance. (Section 4OA2.2)

B. Licensee-Identified Violations

Violations of very low safety significance that were identified by the licensee have been reviewed by inspectors. Corrective actions taken or planned by the licensee have been

entered into the licensee's CAP. These violations and corrective action tracking

numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at rated thermal power (RTP), and operated at or near full power until July 22, 2012 when reactor power was lowered to 52 percent to clear a fouled

circulating water debris filter and power was returned to RTP on July 23, 2012. On August 3,

2012, power was reduced to 70 percent for a rod sequence exchange and power was returned to RTP on August 5, 2012. On August 5, 2012, power was reduced to 90 percent for control rod improvement and power was returned to RTP on the same day. On August 8, 2012, power was

reduced to 65 percent for offsite transmission line work and power was returned to RTP on the

same day. On September 16, 2012, the reactor was shut down for forced outage to replace the

1A and 1B recirculation pump seal assemblies. Reactor startup commenced on September 27, 2012 and the main generator was synchronized to the grid on September 28, 2012. Reactor power was raised to RTP on September 29, 2012. On September 30, 2012 reactor power was

reduced to 75 percent for a scheduled control rod improvement. Power ascension continued to

RTP for the remainder of the inspection period.

Unit 2 began the inspection period at RTP, and operated at or near full power until August 18, 2012, when power was reduced to 70 percent for a rod sequence exchange and power was

returned to RTP on August 19, 2012. On August 20, 2012, power was reduced to 86 percent

for control rod improvement and power was returned to RTP on August 21, 2012. On August

21, 2012, power was reduced to 94 percent for control rod improvement and power was

returned to RTP on August 21, 2012. On September 29, 2012, reactor power was reduced to 94 percent to support a scheduled rod improvement and returned to RTP later that day and maintained RTP for the remainder of the inspection period.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01 - 1 sample)

External Flooding

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with

the design basis probable maximum flood. The inspectors reviewed the Updated Final

Safety Analysis Report (UFSAR), which depicted the design flood levels and protection areas containing safety-related equipment, to identify areas that may be affected by external flooding. The inspectors conducted a site walk-down of the service water

building, to ensure that erected flood protection measures were in accordance with

design specifications. The inspectors reviewed the sealing of equipment below the flood

line, adequacy of watertight doors, drain systems and sumps including check valves, and maintenance and calibration of flood protection equipment. The inspectors also reviewed operating procedures for mitigating external flooding during severe weather to

5 determine if the licensee planned or established adequate measures to protect against

external flooding events.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walk-downs (71111.04Q - 3 samples)

a. Inspection Scope

The inspectors performed partial system walk-downs of the following risk-significant

systems: * Unit 2 "A" train Core Spray (CS) system while "B" residual heat removal/service (RHR/SW) was inoperable for a system outage on July 11, 2012; * Unit 1 Reactor Building Closed Cooling Water (RBCCW) on July 27, 2012; and

• Unit 1 "B" Standby Gas Treatment (SBGT) while the "A" SBGT was inoperable for a maintenance outage on September 19, 2012.

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, 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 that system components and support equipment were aligned correctly and were 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 resolv

ed equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walk-down (71111.04S - 1 sample)

a. Inspection Scope

On September 5, 2012 the inspectors

performed a complete system alignment inspection of the Unit 1 RHR system

to verify the functional capability of the system. This system was selected because it was considered both safety-significant and risk-

6 significant in the licensee's probabilistic risk assessment. 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 CAP to ensure that system equipment alignment problems were being identified and

appropriately resolved.

b. Findings

No findings were identified.

1R05 Fire Protection (71111.05Q - 5 samples)

Quarterly Resident Inspector Tours

a. Inspection Scope

The inspectors conducted fire protection walk-downs which were focused on availability,

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

• Unit 1 and 2 Control Buildings 23'

Elevation 1PFP-CB-7; * Unit 1 Reactor Building East 50' Elevation 1PFP-RB1-1h;

• Unit 1 Turbine Building South Area 38' Elevation 1PFP-TB1-1k; * Unit 2 Reactor Building 50' Elevation 2PFP-RB2-1h; and * Unit 2 Reactor Building North 2A Core Spray Room 2-PFP-RB2-1b.

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 licensee's fire plan.

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

as documented in the plant's 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 plant's 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 licensee's CAP.

7

b. Findings

No findings were identified.

1R06 Flood Protection Measures (71111.06 - 1 sample)

Annual Review of Cables Located in Underground Bunkers/Manholes

a. Inspection Scope

The inspectors conducted an inspection of underground bunkers/manholes subject to

flooding that contain cables whose failure could disable risk-significant equipment. The inspectors performed walk-downs of risk-significant areas, including manhole 2-MH-7SW, to verify that the cables were not submerged in water, that cables and/or splices

appear intact and to observe the condition of cable support structures. When applicable,

the inspectors verified proper dewatering device (sump pump) operation and verified

level alarm circuits are set appropriately to ensure that the cables will not be submerged. Where dewatering devices were not installed; the inspectors ensured that drainage was provided and was functioning properly.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

(71111.07T - 3 samples)

Triennial Review of Heat Sink Performance

a. Inspection Scope

The inspectors selected the Residual Heat Removal (RHR) Heat Exchanger 2A, Diesel

Generator (DG) 3 Jacket Water Cooler and the Core Spray (CS) Room Cooler 1A,

based on their risk-significance in the licensee's probabilistic safety analysis and their

importance to safety-related mitigating syst

em support functions in the NRC's model for Brunswick Nuclear Power Plant, Units 1 and 2.

For the RHR Heat Exchanger 2A, DG 3 Jacket Water Cooler and the CS Room Cooler

1A, the inspectors reviewed the licensee's inspection, maintenance, and monitoring of biotic fouling and macro-fouling programs, to determine if they were adequate to ensure proper heat transfer. This was accomplished by determining whether the methods used were consistent with accepted industry practices. The inspectors also reviewed the

licensee's inspection and cleaning activities had established acceptance criteria

consistent with industry standards, and the as-found results were recorded, evaluated,

and appropriately dispositioned to maintain structural integrity.

For the RHR Heat Exchanger 2A, DG 3 Jacket Water Cooler and the CS Room Cooler 1A, the inspectors reviewed the methods and results of heat exchanger performance inspections. In addition, the inspectors

reviewed the condition and operation of the RHR Heat Exchanger 2A, DG 3 Jacket Water Cooler and the CS Room Cooler 1A to

8 determine if they were consistent with design assumptions in heat transfer calculations and as described in the USFAR. This included determining whether the number of plugged tubes was within pre-established limits based on capacity and heat transfer

assumptions. The inspectors also determined whether the licensee evaluated the potential for water hammer and established adequate controls and operational limits to

prevent heat exchanger degradation due to excessive flow-induced vibration during operation.

The inspectors determined whether the performance of the ultimate heat sink (UHS)-

Cape Fear River and its subcomponents such as piping, intake screens, pumps, valves,

etc. was appropriately evaluated by tests or other equivalent methods to ensure availability and accessibility to the in-plant cooling water systems. The inspectors also reviewed design changes to the service water system and the UHS.

The inspectors reviewed the licensee's operation of the service water system and UHS.

This included a review of licensee's procedures for a loss of the service water system or UHS and the verification that instrumentation, which is relied upon for decision-making, was available and functional. The inspectors also performed a system walk-down on the

service water system to determine whether the licensee's assessment on structural integrity was adequate and interviewed the respective system engineer. For buried or

inaccessible piping, the inspectors reviewed the licensee's pipe testing, inspection, and

monitoring program to determine whether structural integrity was ensured and that any

leakage or degradation was appropriately identified and dispositioned by the licensee.

The inspectors performed a system walk-down of the service water intake structure to determine whether the licensee's assessment on structural integrity and component functionality was adequate. The inspectors also determined whether service water pump bay silt accumulation was monitored, trended, and maintained at an acceptable level by the licensee, and that water level instruments were functional and routinely monitored. The inspectors also determined whether the licensee's ability to ensure

functionality during adverse weather conditions was adequate.

The inspectors reviewed condition reports related to the heat exchangers and heat sink

performance issues to determine whether the licensee had an appropriate threshold for identifying issues and to evaluate the effectiveness of the corrective actions. Records were also reviewed to verify that the licensee actions were consistent with Generic Letter

(GL) 89-13 licensee commitments, Electric Power Research Institute (EPRI) and other

industry guidelines. These inspection activities constituted three heat sink inspection

samples as defined in IP 71111.07-05.

b. Findings

No findings were identified.

9

1R11 Licensed Operator Requalification Program (71111.11Q - 2 samples)

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

On August 13, 2012, the inspectors observed a crew of licensed operators in the plant's simulator during licensed operator requalification examinations to verify that operator

performance was adequate, evaluators we

re identifying and documenting crew performance problems, and to ensure that training was being conducted in accordance

with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance; * crew's 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 crew's performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

Inspectors observed and assessed licensed operator performance in the plant and main control room, particularly during periods of heightened activity or risk and where the activities could affect plant safety. Specifically, on September 16

th, the inspectors observed the Unit 1 shutdown and cooldown evolutions leading up to the forced outage

to repair the recirculation pump seals. The inspectors reviewed various licensee policies

and procedures listed in the Attachment.

• Operator compliance and use of procedures.

• Control board manipulations.

• Communication between crew members.

• Use and interpretation of plant instruments, indications and alarms.

• Use of human error prevention techniques.

• Documentation of activities, including initials and sign-offs in procedures.

• Supervision of activities, including risk and reactivity management.

• Pre-job briefs and crew briefs

10 This activity constituted one License Operator Requalification inspection sample and one Control Room Observation inspection sample.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness (71111.12Q - 3 samples)

a. Inspection Scope

The inspectors evaluated degraded performance

issues involving the following risk-significant systems:

• 1B Nuclear Service Water Pump smoking with vibration and strainer leakage on pump start on June 26, 2012;

• 2A Standby Liquid Cooling accumulator failure before operability run on September

10, 2012 (AR560026560026; and * Performance (unavailability and unreliability) history of the Severe Accident

Mitigation Alternatives (SAMA) diesels

The inspectors reviewed events where ineffective equipment maintenance may have

resulted in equipment failure or 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; and

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and 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.

b. Findings

No findings were identified.

11

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 4 samples)

a. Inspection Scope

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

• Unit 2 yellow risk during emergent work on 2-E21-F015A, 2A Core Spray Full Flow Test Bypass Valve, and scheduled maintenance on 2B RHR/residual heat removal

service water (RHRSW) on July 11, 2012; * Unit 1 yellow risk during 1B Recirculation Pump Variable Frequency Drive power recovery, and planned maintenance on 1A RHR/RHRSW on July 26, 2012; * Unit 1 yellow risk during planned maintenance on 1B RHR/RHRSW September 4 to September 6, 2012; * Unit 1 integrated risk during repair of 1B recirculation pump seal September 17 to September 25, 2012;

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 were identified.

1R15 Operability Evaluations (71111.15 - 5 samples)

a. Inspection Scope

The inspectors reviewed the following five issues:

• Unit 2 High Pressure Coolant Injection (HPCI) elevated thrust bearing temperature

on July 6, 2012 (AR548370548370; * 2D RHRSW Booster pump coupling grease specification evaluation on July 12, 2012 (AR542025542025; * Emergency Diesel Generator (EDG) #3 debris in bearing oil site glass on July 15, 2012 (AR549420549420; * Reactor Building Close Cooling Water (RBCCW) piping corrosion in rattle space on August 21, 2012 (AR557151557151; and

12 * EDG #4 alternate safe shutdown switch contact continuity indications on August 27, 2012 (AR558810558810

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 UFSAR and TS to the licensee's 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.

b. Findings

No findings were identified.

1R18 Plant Modifications (71111.18 - 2 samples)

a. Inspection Scope

The inspectors reviewed the two modifications listed below to determine whether the modifications affected the safety functions of

systems that are important to safety. The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing results and conducted field walk-downs of the modifications to verify that the modifications did not degrade the design bases, licensing bases, and performance capability of the

affected systems.

• Design leak tight barriers at reactor building rattle spaces (EC86304); * Service water building drain hub baffle plate installation (EC 88431)

b. Findings

No findings were identified.

1R19 Post Maintenance Testing (71111.19 - 7 samples)

a. Inspection Scope

The inspectors reviewed the following seven post-maintenance activities to verify that

procedures and test activities were adequate to ensure system operability and functional capability:

• 0PT-12.2D, No. 4 Diesel Generator Monthly Load Test after replacement of the 60X relay on July 23, 2012;

13 * 0PT-08.1.4B, Residual Heat Removal (RHR) Service Water (SW) System Operability Test - Unit 2 RHRSW Loop B after the maintenance outage on July 12, 2012; * 0PT-08.2.2c, Low Pressure Coolant Injection/RHR System Operability Test - Unit 1 RHR Loop A after the maintenance outage on July 27, 2012; * 0PT-12.2C, EDG #3 Operability Test - Unit 2 after repair of jacket water pump on August 16, 2012; * 0PT-15.6, Standby Gas Treatment Operability Test, Unit 1 B after relay replacement on August 15, 2012; * 0PT-10.1.1, Reactor Core Isolation Cooling System Operability Test, Unit 2 after replacement of Electronic Governor - Magnetic (EGM) on August 23, 2012; and * 0PT-80.5, Reactor Pressure Vessel Pressure Test - Unit 1 after repair of 1B recirculation pump seal on September 26, 2012

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

to impact risk. The inspectors evaluated these activities for the following, as applicable:

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 the UFSAR and TS 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 CAP and that the problems were being

corrected commensurate with their importance to safety.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities (71111.20 - 1 sample)

Other Outage Activities

a. Inspection Scope

The inspectors evaluated licensee outage activities for an unscheduled forced outage to

replace the 1B recirculation pump seal assembly. During the outage, the licensee made the decision to replace the 1A recirculation pump seal assembly to address the potential extent of cause/condition. The outage began on September 16, 2012 and concluded on

September 28, 2012. The inspectors reviewed activities to ensure that the licensee

considered risk in developing, planning, and implementing the outage schedule.

Additionally, the inspectors observed or reviewed the reactor shutdown and cool down,

outage equipment configuration and risk management, electrical lineups, control and

monitoring of decay heat removal, control of containment activities, performed a drywell close out inspection, observed reactor startup and heat up activities, and identification and resolution of problems associated with the outage. Documents reviewed are listed

in the Attachment.

14

b. Findings

Introduction: The inspectors identified a Green NCV of TS 3.6.4.1, Secondary Containment because the licensee did not maintain secondary containment operable as

required during an activity considered an operation with a potential for draining the

reactor vessel (OPDRV).

Description: On September 19, 2012, the licensee was replacing the 1B recirculation

pump seal assembly while Unit 1 was in Mode 4 (cold shutdown). In an effort to properly isolate the work area, the recirculation suction and discharge isolation valves were

tagged closed. Due to seat leakage across the isolation valves, the 1B recirculation pump drain valve was uncapped and opened to maintain the pump body partially empty to prevent water from impacting the work area while the pump seal was removed. The

pump drain leakage was sent to the drywell floor drain system. The 1B recirculation

pump seal replacement activity had the potential to drain the reactor vessel below the

top of the fuel because the recirculation loops penetrate the reactor vessel below the top

of active fuel. An OPDRV is described in the licensee's technical specifications as an operation with a potential for draining the reactor vessel. However, the licensee did not recognize or consider this activity as an OPDRV due to inadequate procedural guidance

that was used to exclude this activity as an OPDRV. Specifically, the licensee adopted the definition of an OPDRV in procedure 0OI-01.01 as provided in Enforcement

Guidance Memorandum (EGM)11-003 as any activity that could potentially result in draining or siphoning the RPV water level below the top of the fuel, without taking credit for mitigating measures. However, section 9.16.15.b.(2) of licensee procedure 0OI-

01.01, BNP Conduct of Operations Supplement, stated leakage through mechanical

joints (for example valve or flange packing leaks, seat leakage through an isolation

valve, flange leakage, etc) is not considered an OPDRV. On September 19, 2012, the licensee relaxed Unit 1 secondary containment

from 03:30 a.m. until 09:20 p.m. by opening the reactor building air lock doors on the 20-foot elevation to increase ventilation to the recirculation pump seal replacement work area in the Unit 1 drywell. This resulted in Secondary Containment inoperability while Unit 1 was in Mode 4 during an OPRDV

activity. The inspectors questioned the licensee's Operations staff on the decision to

make secondary containment inoperable during an OPDRV activity. Following this, the licensee restored secondary containment, developed an Operation standing instruction 12-052 to treat this activity as an OPDRV and placed this issue into its CAP as AR

562188. Analysis: The inspectors determined that the failure to maintain secondary containment operable while Unit 1 was in Mode 4 with an OPDRV in progress was a performance deficiency. The performance deficiency was more than minor because it was associated

with the configuration control attribute of the Barrier Integrity Cornerstone, and adversely

affected the cornerstone objective to provide reasonable assurance that physical design

barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events because the Unit 1 secondary containment boundary was not preserved or maintained. The inspectors evaluated the

finding using Inspection Manual Chapter (IMC) 0609, Attachment 4, Phase 1 - Initial

Screening and Characterization of Findings, which required an analysis using IMC 0609

Appendix G since the reactor was in Mode 4 (cold shutdown). The finding was determined to be of very low safety significance (Green) according to IMC 0609

15 Appendix G, Attachment 1, Checklist 6, since a quantitative assessment (Phase 2 or Phase 3 evaluation) was not required. Specifically, the inspectors determined that the licensee maintained adequate mitigation capability for reactor vessel water level

inventory and an event did not occur that could be characterized as a loss of control.

The cause of this finding was directly related to the cross-cutting aspect of Accurate

Procedures in the Resources component of the Human Performance area, because the

licensee did not consider the recirculation pump seal replacement activity to be OPDRV based on procedural guidance that contains exclusions to what are considered OPDRV activities. H.2(c)

Enforcement: Unit 1 TS 3.6.4.1, Secondary Containment, required secondary containment to be operable during modes one, two, three, during movement of recently irradiated fuel assemblies in the secondary containment and during operations with a potential for draining the reactor vessel (OPD

RVs). Contrary to the above, on September 19, 2012, Unit 1 secondary containment was not maintained operable during

an OPDRV activity. The licensee entered this issue in its CAP as AR 562188562188 and

restored secondary containment during the OPDRV activity. Because the licensee entered the issue into its CAP and the finding is of very low safety significance (Green), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC's

Enforcement Policy: NCV 05000325/2012004-01, Failure to Maintain Secondary

Containment Operable during an OPDRV activity. 1R22 Surveillance Testing

.1 Routine Surveillance Testing (71111.22 - 4 samples)

a. Inspection Scope

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

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

commitments, in-service 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.

• 0PT-07.2.4A, Core Spray System Operability Test - Loop A on July 5, 2012; * 0MST-RHR21Q, RHR-LPCI, CSS and HPCI Hi Drywell Pressure Trip Unit Inst Chan

Cal on July 10, 2012; * 0MST-RCIC42R, RCIC Auto-actuation and Isolation Logic Sys Functional on July 24, 2012; and * 0PT-12.12D, No. 4 Diesel Generator Monthly Load Test on August 17, 2012;

b. Findings

No findings were identified.

16

.2 In-Service Testing (IST) Surveillance (71111.22 - 1 sample)

a. Inspection Scope

The inspectors reviewed the performance of Unit 1 LPCI/RHR System Operability Test - Loop B on August 9, 2012 to evaluate the effectiveness of the licensee's 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 licensee's 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 were identified.

.3 Reactor Coolant System Leak Detection Inspection Surveillance (71111.22 - 1 sample)

a. Inspection Scope

The inspectors observed and reviewed the test results for a reactor coolant system leak detection surveillance, 0PT-80.5, Mid-Cycle Maintenance Outage Reactor Pressure

Vessel Pressure Test

, on September 28, 2012

. The inspectors observed in-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 was 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; and test data and results were accurate, complete, within limits, and valid. Inspectors verified that test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared

inoperable; 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.

b. Findings

No findings were identified.

17

1EP6 Emergency Planning Drill Evaluation (71114.06 - 2 samples)

a. Inspection Scope

The inspectors observed site emergency preparedness training drill/simulator scenarios

conducted on July 9, 2012 and July 25, 2012. 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 licensee's post-drill. The inspectors verified that the licensee

properly evaluated the drill's performance with respect to performance indicators and

assessed drill performance with respect to drill objectives.

b. Findings

No findings were identified.

4. OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification (71151 - 6 samples)

.1 Mitigating Systems Cornerstone

a. Inspection Scope

• Mitigating Systems Performance Index, Residual Heat Removal - Unit 1 * Mitigating Systems Performance Index, Residual Heat Removal - Unit 2

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) performance indicators listed above for the period from the third (3

rd) quarter 2011 through the second (2

nd) quarter 2012. The inspectors reviewed the licensee's 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.

b. Findings

No findings were identified.

.2 Barrier Integrity Cornerstone

a. Inspection Scope

• Reactor Coolant System (RCS) Specific Activity - Unit 1

• Reactor Coolant System (RCS) Specific Activity - Unit 2

The inspectors reviewed licensee submittals for the Reactor Coolant System Specific Activity performance indicator for the period from the third (3

rd) quarter 2011 through the

second (2 nd) quarter 2012. The inspectors reviewed the licensee's RCS chemistry

18 samples, TS requirements, issue reports, and event reports for the period to validate the accuracy of the submittals. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample.

• Reactor Coolant System Leakage - Unit 1

• Reactor Coolant System Leakage - Unit 2

The inspectors sampled licensee submittals for the Reactor Coolant System Leakage performance indicator for the period from the third (3

rd) quarter 2011 through the second

(2 nd) quarter 2012.

The inspectors reviewed the licensee's operator logs, RCS leakage tracking data, issue reports, and event reports for the period to validate the accuracy of

the submittals.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems (71152 - 2 samples)

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

a. Inspection 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 licensee's corrective action program. The review was accomplished by reviewing daily action request reports.

b. Findings

No findings were identified.

.2 Assessments and Observations

Selected Issue Follow-up Inspection

UPS-A Failure and Loss of Emergency Response Facility Information System (ERFIS), Plant Process Computer (PPC), Business Network

a. Inspection Scope

The inspectors selected AR 542704542704 UPS-A Failure and Loss of ERFIS, PPC, Business Network, for detailed review. This AR identified that a single failure caused the loss of

ERFIS and Safety Parameter Display System (SPDS) on both units. The inspectors

reviewed the licensee's CAP for ERFIS and SPDS failures in the past. The inspectors

reviewed these reports to verify that the licensee identified the full extent of the issue, performed an appropriate evaluation, and specified and prioritized appropriate corrective actions. The inspectors evaluated the reports against the requirements of the licensee's CAP as delineated in corporate procedure CAP-NGGC-0200, Corrective Action

Program, 10 CFR 50.47, and 10 CFR 50 Appendix E.

19

b. Findings

No findings were identified

a. Inspection Scope

The inspectors selected AR 542704542704 UPS-A Failure and Loss of ERFIS, PPC, Business Network, for detailed review. This AR identified that a single failure caused the loss of ERFIS and Safety Parameter Display System (SPDS) on both units. The inspectors

reviewed the licensee's CAP for ERFIS and SPDS failures in the past. The inspectors

reviewed these reports to verify that the licensee identified the full extent of the issue, performed an appropriate evaluation, and specified and prioritized appropriate corrective actions. The inspectors evaluated the reports against the requirements of the licensee's CAP as delineated in corporate procedure CAP-NGGC-0200, Corrective Action

Program, 10 CFR 50.47, and 10 CFR 50 Appendix E.

b. Findings

Introduction: A self-revealing Green NCV of 10 CFR 50.54(q)(2) was identified for the licensee's failure to properly evaluate or consider the impact to emergency response facilities of design change ESR98-00436 which was implemented in 1999. As a result,

a number of temporary losses of ERFIS, Emergency Response Data System (ERDS),

SPDS, and all displays including radiation monitors for the emergency response facilities

occurred. Specifically, the licensee failed to ensure that adequate emergency response facilities and equipment were available as required by the Brunswick Nuclear Plant Radiological Emergency Plan, Section 1.3.1.3, revision 80, and 10 CFR 50.47(b)(8).

This issue was captured in the licensee's CAP as AR 542704542704

Description: In 1999, the licensee implemented design change ESR98-00436 for the power supply to the ERFIS, ERDS, SPDS, and all displays including RMS for the emergency response facilities. The licensee did not properly evaluate or consider the impact to emergency response facilities and equipment prior to implementation of this design change. As a result, the ERFIS, ERDS, and SPDS systems, and all radiation

monitoring system (RMS) displays were susceptible to a single point power failure mode. The implementation of the design change introduced a single point failure mode which did not meet the design requirements specified in their Design Basis Document (DBD 60) sections 3.6.7.2 and 3.6.7.3. Prior to the licensee's implementation of design

change ESR98-00436 in 1999, this single point vulnerability did not exist as the power

supply system had automatic switching capability on loss of one power source. When the design change was implemented, the ERFIS, ERDS, and SPDS systems and RMS

displays were degraded as demonstrated by the resulting failures of those systems on multiple occasions including July 17, 2004 and June 12, 2012. Additionally, all displays for those systems were lost in all of the emergency facilities including the radiation

monitoring system.

20 On June 13, 2012, the licensee made an ev

ent notification to the NRC Operations

Center, 50.72(b)(3)(xiii) Loss of Emergency Assessment Capability, Offsite Response Capability, or Offsite Communications Capability for the emergency response facilities.

The report delineated that at 5:57 p.m. EDT on June 12, 2012, Brunswick Nuclear Plant

experienced a fault on the Emergency Response Facility Information System (ERFIS)

uninterruptible power supply (UPS) electrical bus 'A'. This resulted in a loss of site

Safety Parameter Display System (SPDS), Emergency Response Data System (ERDS)

and Plant Process Computer (PPC) for both Unit 1 and Unit 2.

During the loss of SPDS, the emergency response capability of that system was lost to

the site. During the loss of ERDS, the automatic data transfer feature of that system

was lost for transmissions to the NRC, however manual data transfer was still available. During the loss of the PPC, automatic core thermal power averaging and automatic core

thermal limit monitoring was lost. Manual calculations were available for these functions. Unit 1 SPDS was restored to the Emergency Operations Facility (EOF) at 7:49 p.m. on

June 12, 2012. Unit 2 SPDS was restored to the EOF at 8:30 p.m. on June 12, 2012.

The inverter was restored to service on June 17, 2012 at 12:00 noon.

Inspectors determined that the licensee did not properly evaluate or consider the impact to all emergency response facilities and equipment prior to implementation of the

ESR98-00436 design change. The inspectors concluded that the ERFIS, ERDS, and

SPDS systems required by the Brunswick Nuclear Plant Radiological Emergency Plan

were degraded from 1999 when the design change was installed to present. Compensatory measures were put in place during the June 2012 event to manually obtain and log the required data from the instrumentation in the control room and

transmit to the emergency response facilities, and after the June 2012 event, the

licensee initiated a design change to restore the power configuration to those systems

back to the original design which would remove this failure mechanism.

Analysis: The licensee's failure to properly evaluate or consider the impact to emergency response facilities of design change ESR98-00436 which was implemented in 1999 was a performance deficiency. Specifically, the licensee introduced a single point failure mode which did not meet the design requirements specified in their Design

Basis Document (DBD 60) sections 3.6.7.2 and 3.6.7.3. This resulted in the licensee's failure to ensure that adequate emergency response facilities and equipment were available as delineated in the Updated Final Safety Analysis Report (UFSAR) Section 7.7.1.9, and required by the Brunswick Nuclear Plant Radiological Emergency Plan,

Section 1.3.1.3, revision 80, and 10 CFR 50.47(b)(8).

The finding was more than minor because it adversely affected the Emergency Preparedness Cornerstone objective of ensuring that the licensee was capable of

implementing adequate measures to protect the health and safety of the public in the

event of a radiological emergency. Specifically, the Facilities and Equipment attribute was affected during the time when the ERFIS, ERDS, SPDS, and all displays including

radiation monitors for the emergency response facilities were degraded, and as a result

did not meet 10 CFR 50.47(b)(8) Planning Standard program element, adequate emergency facilities and equipment to support the emergency response are provided

and maintained. The finding was assessed for significance in accordance with NRC IMC 0609, Appendix B Emergency Preparedness Significance Determination Process.

21 Attachment 2 of Appendix B, Failure to Comply Significance Logic is as follows: Failure to comply; Loss of Risk Significant Planning Standard Function (RSPS), No; RSPS Degraded Function, No; Loss of Planning Standard Function, No; the result is a Green

finding. The inspectors determined that this resulted in a low safety significance finding

(Green). No cross-cutting aspect was assigned to this finding because the performance

deficiency occurred more than three years ago and is not reflective of current plant

performance.

Enforcement: 10 CFR 50.54(q)(2) requires, in part, a licensee to follow and maintain the

effectiveness of an emergency plan that meets the requirements in Appendix E to this part and, for nuclear power reactor licensee, the planning standards of 10 CFR 50.47(b).

The Brunswick Nuclear Plant Radiological Emergency Plan, Section 1.3.1.3, revision 80, states in part that special provisions have been made to assure that ample space and proper equipment are available to effectively respond to a full range of possible

emergencies. Contrary to the above, from 1999, when design change ESR98-00436 was installed, until the compensatory measures were put in place in June 2012, the

licensee failed to maintain adequate emergency facilities and equipment to support emergency response when the ERFIS, ERDS, SPDS, and all displays including radiation monitors for the emergency response facilities were degraded due to the implementation

of the design change. This resulted in failures of those systems on July 17, 2004 and

June 12, 2012. The licensee has compensatory measures in place, entered this issue

their CAP as AR 542704542704 and initiated a design change to restore the power

configuration back to the original design. Because the licensee entered the issue into its CAP and the finding is of very low safety significance (Green), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC's Enforcement Policy: NCV

05000325; 324/2012004-02, Failure to Maintain Reliability and Availability of Emergency

Response Equipment for Emergency Response Facilities.

.3 Assessments and Observations

Selected Issue Follow-up Inspection: EDG 2 wiring associated with Alternate Safe Shutdown (ASSD) Switch 2-DG-SS-A1

a. Inspection Scope

The inspectors performed a detailed review of AR 557897557897associated with the wiring for

the EDG 2 Alternate Safe Shutdown (ASSD) Switch 2-DG-SS-A1. The issue was

discovered during a planned system outage for EDG2 during the week of August 26.

The inspectors verified that the issue was captured completely and accurately in the CAP. The inspectors evaluated the licensee's operability determinations and performed walk-downs with licensee staff of applicable fire areas as needed. The inspectors

followed the licensee's actions to restore the wiring to its proper configuration and also

verified the extent of condition inspections for the remaining EDGs 1, 3 and 4 were

completed in a timely manner. The inspectors reviewed the licensee's reportability

evaluation and subsequent 8-hour report made to the NRC in accordance with 10 CFR 50.72(b)(3)(ii)(B). Additional documents reviewed are listed in the Attachment.

b. Findings

22 Introduction: The inspectors opened an unresolved item (URI) for this issue of concern to determine if a performance deficiency existed.

Description: A wiring discrepancy was identified during inspection of the EDG 2 ASSD switch 2-DG-SS-A1. A contact in the circuit was determined to be bypassed that would

have the potential to prevent proper isolation of the EDG2 control circuits from the Main

Control Room (MCR) during an Appendix R fire event. The inspectors plan to review the licensee's cause evaluation for this event and determine if a performance deficiency existed. This issue is being tracked as URI 05000325; 324/2012004-03, EDG2 wiring on

ASSD switch.

4OA3 Follow-up of Events (71153 - 2 samples)

.1 Notice of Unusual Event for Fire in the Protected Area

a. Inspection Scope

For the plant event listed below, the inspectors reviewed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The

inspectors communicated the plant events to appropriate regional NRC personnel, and compared the event details with criteria contained in IMC 0309, "Reactive Inspection

Decision Basis for Reactors," for consideration of potential reactive inspection activities.

As applicable, the inspectors verified that the licensee made appropriate emergency classification assessments and properly r

eported the event in accordance with 10 CFR 50.72. The inspectors reviewed the licensee's follow-up actions related to the events to assure that the licensee implemented appropriate corrective actions commensurate with

their safety significance.

• On August 2, 2012, a fire existed in the protected area on the Units 1 and 2 turbine building roof for approximately two hours, meeting the criteria for a Notice of Unusual Event declaration.

b. Findings

One licensee identified violation is documented in Section 4OA7 of this report.

.2 (Closed) LER 05000325/2012-004-00, High Pressure Coolant Injection (HPCI)

Inoperable Due to Erratic Governor Operation

a. Inspection Scope

On May 2, 2012, Unit 1 HPCI was declared inoperable due to erratic governor operation

during Surveillance Test 0PT-09.2, HPCI Syst

em Operability Test. The erratic governor operation was due to the failure of the Ramp Generator Signal Convertor (RGSC). The

licensee determined that the root cause of the RGSC failure was due to a lack of a

replacement preventative maintenance (PM) for the RGSC, which had been installed for at least 22 years. The corrective actions included replacing the RGSC and creating a PM task to replace the RGSCs. The licensee documented the root cause evaluation in

23 NCR 534364. The inspectors reviewed the LER, the NCR, and corrective actions to determine whether the station adequately evaluated the condition.

b. Findings

One licensee identified violation is documented in Section 4OA7 of this report. This LER is closed.

4OA5 Other Activities

.1 (Discussed) NRC Temporary Instruction (TI) 2515/187, Inspection of Near-Term Task Force Recommendation 2.3 Flooding Walk-downs, and NRC TI 2515/188, Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walk-downs

a. Inspection Scope

Inspectors accompanied the licensee on a sampling basis, during their flooding and seismic walk-downs, to verify that the licensee's walk-down activities were conducted using the methodology endorsed by the NRC. T

hese walk-downs are being performed at all sites in response to a letter from t

he NRC to licensees, entitled "Request for Information Pursuant to Title 10 of the

Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-Ichi Accident," dated March 12, 2012 (ADAMS Accession No. ML12053A340).

Enclosure 3 of the March 12, 2012, letter requested licensees to perform seismic walk-

downs using an NRC-endorsed walk-down methodology. Electric Power Research Institute (EPRI) document 1025286 titled, "Seismic Walk-down Guidance," (ADAMS

Accession No. ML12188A031) provided t

he NRC-endorsed methodology for performing seismic walk-downs to verify that plant features, credited in the current licensing basis

(CLB) for seismic events, are available, functional, and properly maintained.

Enclosure 4 of the letter requested licensees to perform external flooding walk-downs using an NRC-endorsed walk-down methodology (ADAMS Accession No. ML12056A050). Nuclear Energy Industry (NEI) document 12-07 titled, "Guidelines for

Performing Verification Walk-downs of Plant Protection Features," (ADAMS Accession

No. ML12173A215) provided the NRC-endors

ed methodology for assessing external flood protection and mitigation capabilities to verify that plant features, credited in the CLB for protection and mitigation from external flood events, are available, functional, and properly maintained.

b. Findings

Findings or violations associated with the flooding and seismic walk-downs, if any, will be documented in future reports.

24

.2 (Discussed) Temporary Instruction (TI) 2515/182 - Review of the Implementation of the Industry Initiative to Control Degradation of Underground Piping and Tanks, Phase 1

a. Inspection Scope

Leakage from buried and underground pipes has resulted in ground water contamination

incidents with associated heightened NRC and public interest. The industry issued a guidance document, Nuclear Energy Institute (NEI) 09-14, "Guideline for the

Management of Buried Piping Integrity," (ADAMS Accession No. ML 1030901420), to describe the goals and required actions (commitments made by the licensee) resulting from this underground piping and tank initiative. On December 31, 2010, NEI issued

Revision 1 to NEI 09-14, "Guidance for the Management of Underground Piping and

Tank Integrity," (ADAMS Accession No. ML 110700122), with an expanded scope of

components which included underground piping that was not in direct contact with the soil and underground tanks. On November 17, 2011, the NRC issued TI-2515/182, "Review of the Industry Initiative to

Control Degradation of Underground Piping and Tanks," to gather information related to the industry's implementation of this initiative.

The instructors reviewed the licensee's programs for buried pipe and underground piping

and tanks in accordance with TI-2515/182 to determine if the program attributes and

completion dates identified in Section 3.3 A and 3.3 B of NEI 09-14, Revision 1, were contained in the licensee's program and implementing procedures. For the buried pipe and underground piping program attributes, with completion dates that had passed, the

inspectors reviewed records to determine if the attribute was in fact complete and to

determine if the attribute was accomplished in a manner which reflected good or poor

practices in management.

b. Observations

The licensee's buried piping and underground piping and tanks program was inspected in accordance with paragraphs 03.01.a through 03.01.c of TI-2515/182 and was found to

meet all applicable aspects of NEI 09-14 Revision 1, as set forth in Table 1 of the TI.

Based upon the scope of the review described above, Phase I of TI-2515/182 was

completed.

c. Findings

No findings were identified.

4OA6 Management Meetings

Exit Meeting Summary

On July 19, 2012, the inspectors presented inspection results of the triennial heat sink

inspection to Mr. Michael Annacone and other members of the licensee staff. The

25 inspectors confirmed that none of the potential report input discussed was considered

proprietary.

On September 18, 2012, the inspector presented inspection results of the TI-182, Phase

1 of the Underground Piping and Tanks Inspection by conference call to Mr. James

Burke, Site Director of Engineering, and other members of the licensee staff. The

inspector verified that all proprietary information was returned to the licensee.

On October 11, 2012, the inspectors presented inspection results from the quarterly

inspection to Mr. Annacone and other members of the licensee staff. The inspectors

confirmed that any proprietary information received during the inspection period were

properly controlled or returned to licensee staff.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee

and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as NCVs.

• 10 CFR 50.54(q) requires, in part, a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards of 10 CFR 50.47(b). Title 10 CFR 50.47(b)(4)

requires, in part, a standard emergency classification and action level scheme be used by the licensee. Procedure 0PEP-02.1.1, Emergency Control - Notification

of Unusual Event, Alert, Site Area Emergency, and General Emergency, Step 5.7.2 states, that the emergency declaration will be made within 15 minutes after the availability of indications to plant operators that an emergency action level

has been exceeded. Procedure 0PEP-02.1, Initial Emergency Actions, HU2.1,

requires the declaration of an Unusual Event when a fire is not extinguished

within 15 minutes of control room notification or verification of a control room fire alarm in any Table H-1 or Table H-3 areas. Table H-1 includes the turbine building. Contrary to the above, on August 2, 2012, a Notice of Unusual Event

(NOUE) was not classified within 15 minutes of a fire within the protected area

not being extinguished within 15 minutes of detection. Specifically, when a fire

was reported on the Turbine Building roof to the Control Room and was not

extinguished within 15 minutes, conditions were met for classification of EAL HU2.1 in accordance with

Procedure 0PEP-02.1;

however, the EAL was not classified until approximately eight hours after the fire started. This issue was

entered into the licensee's CAP as NCR 552984 and the licensee is performing a

root cause evaluation.

Corrective actions included making a one hour report to the NRC for discovery of a condition that met the EAL classification for an NOUE after the fact. The inspectors determined the finding was associated with an actual event implementation problem, and assessed the significance using IMC 0609, Appendix B, "Emergency Preparedness Significance Determination

Process." Using the Emergency Preparedness SDP, Sheet 1, "Failure to

Implement (Actual Event) Significance Logic" the inspectors determined the finding was of very low safety significance (Green) because the licensee failed to implement a risk significant planning standard (10 CFR 50.47(b)(4)) during an

actual Notice of Unusual Event.

26

• 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or

drawings. Licensee procedure ADM-NGGC-0107, Equipment Reliability Process

Guideline, steps 9.4.9 and 9.4.10 req

uired component experts and preventive maintenance (PM) optimization to determine if there was a cost effective PM to prevent failure and then to develop the PM model. Contrary to the above, the Unit 1 high pressure coolant injection (HPCI) ramp generator signal converter (RGSC) did not have the appropriate preventive maintenance to prevent failure. As a result, the Unit 1 high pressure coolant injection (HPCI) system failed the HPCI System Operability Test performed on April 30, 2012 and was declared

inoperable. The licensee entered this issue into the CAP as NCR 534364. Corrective actions included replacing the RGSC and creating a PM task to replace the RGSCs on a specified frequency. Using IMC 0609, Appendix A,

"Phase 1 Initial Screening and Characterization of Findings," the inspectors

determined this finding required a Phase 2 analysis. The Phase 1 screened this

Mitigating Systems Cornerstone finding to Phase 2 because the finding represented a loss of HPCI system and/or function. The inspectors, with the assistance of the regional Senior Risk Analyst, performed a Phase 2 analysis

using the Saphire 8 Model. 109 hours0.00126 days <br />0.0303 hours <br />1.802249e-4 weeks <br />4.14745e-5 months <br /> of unavailability time was used for the

analysis since HPCI was not required during the refueling outage from February

23, 2012 through April 29, 2012. Based on the results of the Phase 2 analysis,

the inspectors determined the finding was of very low safety significance (Green).

ATTACHMENT: SUPPLEMENTAL INFORMATION

Attachment SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

M. Annacone, Site Vice President

A. Brittain, Manager - Security

J. Burke, Director - Site Engineering

K. Croker, Supervisor - Emergency Preparedness

C. Dunsmore, Manager - Shift Operations P. Dubrouillet, Manager - Training G. Galloway, Acting Manager, Nuclear Oversight

C. George, Manager - BOP Systems

S. Gordy, Manager - Maintenance

L. Grzeck, Manager - Regulatory Affairs

M. Hamm, Superintendent - Mechanical Maintenance F. Jefferson, Manager - Reactor Systems Engineering

J. Kalamaja, Manager - Operations

J. Krakuszeski, Plant General Manager

R. Mosier, Communication Specialist

A. Padleckas, Superintendent - Nuclear Operations Performance D. Petrusic, Superintendent - Environmental and Chemistry A. Pope, Manager - Nuclear Support Services

J. Price, Manager- Design Engineering

W. Richardson, Engineering

T. Roeder, Supervisor - Chemistry T. Sherrill, Licensing Senior Technical Specialist P. Smith, Superintendent - Electrical, Instrumentation, and Controls Maintenance

M. Talon, Buried Piping Program Manager

J. Terrell, Corporate Buried Piping Program Manager

M. Turkal, Lead Engineer - Technical Support

J. Vincelli, Manager - Environmental and Radiological Controls B. Wilder, Engineering E. Wills, Director - Site Operations

NRC Personnel

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

Attachment LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000325/2012004-01

05000325;324/2012004-02 NCV NCV Failure to Maintain Secondary Containment Operable During an OPDRV Activity. (Section 1R20)

Failure to Maintain Reliability and Availability of

Emergency Response Equipment for Emergency

Response Facilities. (Section 4OA2.2)

Opened

05000325;324/2012004-03

URI

EDG2 Wiring on ASSD Switch (Section 4OA2.3)

Closed

05000325/2012-004-00

LER

High Pressure Coolant Injection (HPCI) Inoperable

Due to Erratic Governor Operation (Section 4OA3.2)

Discussed Temporary Instruction

2515/187 TI Inspection of Near-Term Task Force Recommendation 2.3 Flooding Walk-downs (Section 4OA5.1)

Temporary Instruction

2515/188 TI Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walk-downs (Section 4OA5.1)

Temporary Instruction

2515/182 TI Review of the Implementation of the Industry Initiative to Control Degradation of Underground Piping and Tanks, Phase 1 (Section 4OA5.2)

Attachment LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

Procedures

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

0PEP-02.6, Severe Weather

2APP-UA-01, Annunciator Procedure for Panel UA-01 2APP-UA-28, Annunciator Procedure for Panel UA-28 2OP-43, Service Water System Operating Procedure

OPS-NGGC-1305, Operability Determinations

Nuclear Condition Reports

556860 556861 556862 556863 556864 556865

556866 556867 556868 556869 556870 557375

555023 545354 553946

Work Orders

550098 550100 550102 550015 545859 545861

1828825 1828826 1643223 1775054

Drawings D-02778, Reactor Building Floor and Wall Sleeves Tabulation - Sheet No 1 Unit No 2

D-02779, Reactor Building Floor and Wall Sleeves Tabulation and Details - Sheet No 2 D-11597, Backdraft Damper with Extra Deep Frame F-0424, Service Water Intake Structure Units 1 & 2 Ventilation System & Drainage Piping

LL-FB-02103, Reactor Building, Elevation -17'0", Fire Barrier Penetrations, RHR-HPCI Room

North Wall

Miscellaneous

0PIC-LS001, Omnitrol (Valrec) Level Control Switch Model 613, Single Actuator DBD-106, Hazards Analysis

Engineering Change 80408R0, Flooding Design Basis Update

Individual Plant Examination for Exte

rnal Events Submittal, June 1995 Link Seal Vendor Manual Quick Hit Self-Assessment 541666-15, Emergency Action Level Functionality SD-43, Service Water System

URS List of Flood Features Inspected

URS Near Term Force Recommendations 2.3: Flooding, Project Number 30703-007

Section 1R04: Equipment Alignment

Procedures

Procedure 2OP-18, Core Spray System Operating Procedure

1OP-17, RHR System Operating Procedure

2OP-10, Standby Gas Treatment System Operating Procedure

4 Attachment

Drawings D-25024, Reactor Building Core Spray System Piping Diagram 9527-D-2025, sheets 1A and 1B, RHR System, Unit 1

F-04073, Reactor Building Standby Gas Treatment Piping Diagram

Miscellaneous

DBD-10, Design Basis Document Standby Gas Treatment System

SD-10, System Description St

andby Gas Treatment System

Section 1R05: Fire Protection

Procedures

0FPP-014, Control of Combustible, Transient Fire Loads, and Ignition Sources 0PFP-CB, Control Building Pre-Fire Plans

OPLP-01, Fire Protection Program Document

OPLP-01.2, Fire Protection System Operability, Action, and Surveillance Requirements

0PFP-013, General Fire Plan 1PFP-RB, Reactor Building Pre-Fire Plans Unit 1 2PFP-RB, Reactor Building Prefire Plans Unit 2

OPT-34.11.2.0, Portable Fire Extinguisher Inspection

1PFP-TB, Turbine Building Prefire plans

Section 1R06: Flood Protection

Nuclear Condition Reports

490292

Drawings F-03347, East Yard Area - Units No. 1 & 2 Electrical Underground Duct Runs Manholes F-03343, East Yard Area - Units No. 1 & 2 Electrical Underground Duct Runs Plan

Section 1R07: Heat Sink Performance

Procedures

0ENP-2704, Administrative Control of NRC Generic Letter 89-13 Requirements 0ENP-2705, Service Water Heat Exchanger Thermal Performance Testing

0PM-ACU500, Inspection and Cleaning of the RHR/Core Spray Room Aerofin Cooler Air Filters

and Coolers 0PM-STU500, Service Water Intake Structure Inspection and Cleaning 0CM-ENG521, Perfex Cooler Inspection and Repair 0E&RC-3212, Service/Circulating Water Chlorine Sampling

1PM-MEC502, Nuclear Service Water Header Inspection

1PM-MEC506, Conventional Service Water Header Inspection

2PM-MEC501, Nuclear Service Water Header Inspection

2PM-MEC505, Conventional Service Water Header Inspection 0PT-08.1.4a, RHR Service Water System Operability Test - Loop A 0AOP-18.0, Nuclear Service Water system Failure

0AOP-19-0, Conventional Service Water System Failure

5 Attachment 0AOP-37.1, Intake System Blockages 0O1-03.4, Unit 0 Outside Auxiliary Operator Daily Check Sheets IPT-24.1-1, Service Water Pump and Discharge Valve Operability Test

0AI-81, Water Chemistry Guidelines

0A1-86, Service/Circulating Water Treatment Strategic Plan

0SMP-SW1500, Sodium Hypochlorite Injection to the SW System

Nuclear Condition Reports

392541 507589 339272 539775 497132 542399

Work Orders

01582632 01324149

Drawings BN 43.0.01, Service Water System

Calculations

OSW-0096, Calculation for Tube Plugging and Fouling of Service Water Safety Related Heat

Exchangers OSW-0097, RHR and Core Spray Room Cooler Performance

G0050C-04, Design Basis Heat Loads from Vital Heat Exchangers

Miscellaneous

LTAM-BNP-12-0009, Formal Water Hammer Analysis for Service Water DBD-43, Service Water System

DBD-17, Residual Heat Removal System

System Health Report, Q1-2012, RBCCW Unit 1

System Health Report, Q1-2012, Service Water System Health Report, Q1-2012, Emergency Diesel Generators Program Health Report, Q1-2012, GL 89-13 Program

EC-84365, Temporary Removal of Degraded Coating on Internal Surfaces of Service Water Pump Discharge Pipe Spools and Elbows EC-85258, Replace Nuclear and Conventional Service Water Pump Discharge Elbow

2-E11-B002A, Final Eddy Current Inspection Report for RHR Heat Exchanger 2A, March 15, 2011 EDG-3-JWC-2010, Final Eddy Current Inspection Report for EDG-3 Jacket Water Cooler May 18, 2010 SD-63, Sodium Hypochlorite Injection System

Procedure Revision Requests

00549906 00549915 00549919 00549920 00549923 00549924

00550041 00550333

Section 1R11: Licensed Operator Requalification

Procedures

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

General Emergency

6 Attachment 0PEP-02.1, Initial Emergency Actions AOP-17, Turbine Building Closed Cooling Water System AOP-19, Conventional Service Water System Failure

EM-78, Nuclear Power Facility Emergency Notification Form

ENP-24.5, Reactivity Control Planning

2EOP-01-LPC, Level/Power Control

2EOP-01-RSP, Reactor Scram Procedure OPS-NGGC-1000, Fleet Conduct of Operations TRN-NGGC-0420, Conduct of Simulator Training and Evaluation

Miscellaneous

LORX-IPO-003 Scenario Technical Specifications 3.7.1, Residual Heat Removal Service Water System Technical Specifications 3.7.2.E, Service Water System and Ultimate Heat Sink

Section 1R12: Maintenance Effectiveness

Procedures

1OP-43, Service Water System Operating Procedure

MNT-NGGC-0001, Maintenance Rework Program

0PT-06.1, SLC System Operability Test

0AOP-36.2, Station Blackout

0PT-12.22, Load Test for SAMA Diesels ADM-NGGC-0101, Maintenance Rule Program

Nuclear Condition Reports

546346 554488 549265 519703 477622 436705

436703 409663 408997 401149 477561 477622

401149

Work Orders

1802757 2104000 1868030 1746181

Drawings Miscellaneous

FP-20234, R.P Adams CO, Inc, Strainers, Poro-Edge Automatic

Technical Specification 3.7.2, Service Water System and Ultimate Heat Sink

SD-05, Standby Liquid Control System Maintenance Rule Unavailability Reports, January 2012 through August 2012

SAMA Diesels System Health Report, Q2-2012

Section 1R13: Maintenance Risk Assessment and Emergent Work Control

Procedures

0AI-144, Risk Management 0AP-022, BNP Outage Risk Management

0AP-025, BNP Integrated Scheduling

7 Attachment ADM-NGGC-0006, Online EOOS Model ADM-NGGC-0104, Work Management Process

WCP-NGGC-0500, Work Activity Integrated Risk Management Program

OPS-NGGC-1311, Protected Equipment

Nuclear Condition Reports

559242 Miscellaneous

BNP EOOS Risk Assessment

BNP EOOS Risk Assessment Report for Work Week 36

Section 1R15: Operability Evaluations

Procedures

0PT-12.2C, No. 3 Diesel Generator Monthly Load Test

FP-20322, Diesel Generator Instruction Manual

OPS-NGGC-1305, Operability Determinations OPS-NGGC-1307, Operational Decision making

Nuclear Condition Reports

250203 310500 318607 548370 549420 558810

Work Orders

542970

Drawings D-25028, Reactor Building Closed Cooling Water System F-09348, Diesel Generator No. 4 Circuits Control Wiring Diagram

Miscellaneous

EDG 1-4 Generator Bearing Oil Analysis

SD-39, Emergency Diesel Generators

Section 1R18: Plant Modifications

Procedures

EGR-NGGC-0028 Engineering Evaluation

0AI-68 Brunswick Nuclear Plant Response to Severe Weather Warnings

Engineering Changes

EC 88431, Service Water Building Drain Hub Baffle Plate Installation

EC 86304, Design Leak Tight Barriers at Reactor Bldg Rattle Spaces

Nuclear Condition Reports

559173 490292

8 Attachment

Drawings D-02041, Service Water System Piping Diagram F-04024, Service Water Intake Structure Ventilation System & Draining Piping

F-01027, Seismic Isolation Space

Miscellaneous

UFSAR Updated Final Safety Analysis Report

Section 1R19: Post Maintenance Testing

Procedures

0PT-08.2.2C, LPCI/RHR System Operability Test 0PT-80.5, Mid-Cycle Maintenance Outage Reactor Pressure Vessel Pressure Test

Nuclear Condition Reports

551048

Work Orders

1951825 2028895 2034614 2112268

Drawings D-25026, Sheet 2A, Residual Heat Removal System, Unit 1

Miscellaneous

Technical Specifications 3.5.1, Emergency Core Cooling System - Operating

Section 1R20: Outage Activities

Procedures

0GP-01, Prestartup Checklist

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

0GP-03, Unit Startup and Synchronization

0GP-05, Unit Shutdown

0GP-10, Rod Sequence Checkoff Sheets 0AI-127, Primary Containment Inspection and Closeout 0AP-22, BNP Outage Risk Management

0OI-01-01, BNP Conduct of Operations Supplement

0SP-12-001, EGM 11-003 OPDRV Activities

Nuclear Condition Reports

561831 561899 561173 562188

Drawings D-20022 Sheet 1, Piping Diagram Extraction Steam System, Unit 1

Miscellaneous

Main Control Room (MCR) Logs

Outage Control Center (OCC) Logs

9 Attachment Unit 1 Key Safety Function Component Status Sheets Operations Standing Instruction 12-052

Section 1R22: Surveillance Testing

Procedures

0PT-07.2.4a, Core Spray System Operability Test - Loop A 0MST-RHR21Q, CSS and HPCI Hi Drywell Pressure Trip Unit Chan Cal 0MST-RCIC42R, RCIC Auto-actuation and Isolation Logic Sys Functional

0PT-12.12D, No. 4 Diesel Generator Monthly Load Test

0PT-08.2.2B, LPCI/RHR System Operability Test - Loop B

0PT-80.5, Mid-Cycle Maintenance Outage Reactor Pressure Vessel Pressure Test

Nuclear Condition Reports

547945

Work Orders

2107649

Drawings D-25024, Reactor Building Core Spray System Piping Diagram

Miscellaneous

Technical Specification 3.5.1, Emergency Core Cooling System - Operating UFSAR Section 6.3.3.7, Lag Times

Section 1EP6: Drill Evaluation

Procedures

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

General Emergency

0PEP-02.1, Initial Emergency Actions

0PEP-02.6.20, Dose Projection Coordinator

0PEP-03.4.8, Offsite Dose Projections for Monitored Releases

2EOP-01-RSP, Reactor Scram Procedure EM-78, Nuclear Power Facility Emergency Notification Form

EMG-NGGC-0002, Offsite-Dose Assessment

OPS-NGGC-1000, Fleet Conduct of Operations

Nuclear Condition Reports

551255 551620 551698 552439

Section 4OA1: Performance Indicator Verification

Procedures

0E&RC-1006, Operation of the Reactor Building Sample Stations 0E&RC-2212, Calibration/Operation of Genie Gamma Spectroscopy System

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

10 Attachment

Miscellaneous

BNP-PSA-069, NRC Mitigating System Performance Index (MSPI) Basis Document

Unit 1 RHR MSPI Margin Reports, July 2011 to June 2012

Unit 2 RHR MSPI Margin Reports, July 2011 to June 2012

Unit 1 RHR MSPI Derivation Reports, July 2011 to June 2012

Unit 2 RHR MSPI Derivation Reports, July 2011 to June 2012 REG-NGGC-0009, Attachment 4 - MSPI Unavailability Data Sheets, July 2011 to June 2012 REG-NGGC-0009, Attachment 6 - MSPI Unreliability Data Sheets, July 2011 to June 2012

Section 4OA2: Identification and Resolution of Problems

Procedures

CAP-NGGC-0200, Condition Identification and Screening Process

CAP-NGGC-0205, Condition Evaluation and Corrective Action Process

CAP-NGGC-0206, Performance Assessment and Trending

OERP, Radiological Emergency Response Plan OPLP-37, Equipment Important to Emergency Preparedness and ERO Response OPEP-02.6.21, Emergency Communicator

OPEP-04.2, Emergency Facilities and Equipment

ADM-NGGC-0119, Nuclear Safety Culture Program, Revision 01

Nuclear Condition Reports

AR 00201153, Adverse Trend - Failed ERFIS Multiplexer Modules ACE CR 542704, UPS-A Failure and Loss of ERFIS, PPC, Business Network

Miscellaneous

Down Time by Computer System Log

NIT Key performance indicators ESR 98-00436, RAINS 99-0045, 50.59 Evaluation

ESR 98-00436, RAINS 99-0045, 50.54q Evaluation

Section 4OA3: Event Followup

Procedures

0PT-09.2, HPCI System Operability Test

0PT-09.3, HPCI System - 165 PSIG Flow Test

ADM-NGGC-0107, Equipment Reliability Process Guideline

0PEP-02.1, Initial Emergency Actions 0PEP-02.1.1, Emergency Control - Notification of Unusual Event, Alert, Site Area Emergency, and General Emergency 0PEP-02.2.1, Emergency Action Level Bases

Nuclear Condition Reports

534364 552815 552984

Work Orders

2107224 2107264 2107271 2107313

11 Attachment

Drawings 1-FP-02039, General Electric Gas Control Piping Diagram

D-02055, Piping Diagram, Carbon Dioxide & Hydrogen Systems, Units 1 & 2

Miscellaneous

10 CFR 50.72 Event Report 47893, High Pressure Coolant Injection Inoperable due to Erratic Governor Operation, May 2, 2012 LER 1-2012-004-00, High Pressure Coolant Injection Inoperable due to Erratic Governor Operation, June 29, 2012 System Description 19, High Pressure Coolant Injection System

Technical Specification 3.5.1, Emergency Core Cooling Systems and Reactor Core Isolation

Cooling Event Notification, Discovery of a Condition that Met the EAL Classification of an Unusual Event (After-the-Fact), August 2, 2012 NUREG-1022, Event Reporting Guidelines

Operator Logs, August 2, 2012

SD-59, Hydrogen Water Chemistry System

Section 4OA5: Other Activities

Procedures

EGR-NGGC-0209, Buried Piping Program, Rev. 3 EGR-NGGC-0513, License Renewal Buried Piping and Tanks Inspection Program, Rev. 3 0AOP-13.0, Operation During Hurricane, Flood Conditions, Tornado, or Earthquake

0PEP-02.6, Severe Weather

2APP-UA-01, Annunciator Procedure for Panel UA-01

2APP-UA-28, Annunciator Procedure for Panel UA-28 2OP-43, Service Water System Operating Procedure

OPS-NGGC-1305, Operability Determinations

MNT-NGGC-004, Scaffolding Control

0PT-34.2.2.1, Fire Door, Pressure Boundary Door, ASSD Access/Egress Door, and Severe Weather/Flood Control Door Inspections 0AI-68, Brunswick Nuclear Plant Response to Severe Weather Warnings 0PEP-02.1.1, Emergency Control-Notification of Unusual Event, Alert, Site Area Emergency, and General Emergency 0PEP-02.6, Severe Weather

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

Nuclear Condition Reports

551646 551838 551964 550469 559173 556860

556861 556862 556863 556864 556865 556866

556867 556868 556869 556870 557375 555023

545354 553946

Work Orders

550098 550100 550102 550015 545859 545861

1828825 1 1828826 1643223 1775054 2113607

12 Attachment

Work Requests

546632 546540 546541 546543 544971 546174

546823 546824 546203 546274 546278

Drawings D-11099, Reactor Building Miscellaneous Steel Pool Liners D-2274, Diesel Cooling Water D-25049, Reactor Building Piping Diagram Fuel Pool Cooling & Filtering System, Unit 1

D-26007, Reactor Building Fuel Pool Cooling & Filter System Plan EL 80'-0" & Sections

D-26009, Reactor Building Fuel Pool Cooling & Filter System Miscellaneous Plans & Sections

D-27010, Supplemental Spent Fuel Pool Cooling System F-25008, Reactor Building Arrangement & Details, Fuel Pool D-02778, Reactor Building Floor and Wall Sleeves Tabulation - Sheet No 1 Unit No 2

D-02779, Reactor Building Floor and Wall Sleeves Tabulation and Details - Sheet No 2

D-11597, Backdraft Damper with Extra Deep Frame

F-0424, Service Water Intake Structure Units 1 & 2 Ventilation System & Drainage Piping LL-FB-02103, Reactor Building, Elevation -17'0", Fire Barrier Penetrations, RHR-HPCI Room

North Wall 1-FP-09319, Reactor Building Railroad Doors

Corrective Action Document

PRR 562261, Revise EGR-NGGC-0209 to strengthen the tie to the License Renewal Program

Miscellaneous

Calculation 2RB2-0012, Analysis for Spent Fuel Pool - Elevation of Top of Active Fuel

Engineering Change 80408R0, Flooding Design Basis Update

EPRI Report 1025286, Seismic Walk-down Guidance for Resolution of Fukushima Near-Term Task Force Recommendation 2.3: Seismic FP-75090, International Instruments INC, Instruments, Switchboard, Edgewise

System Description SD-43, Service Water System

UFSAR Section 9.1.3.3, Fuel Pool Cooling and Cleanup System, Safety Evaluation

Units 1 and 2, Flood Protection Feature 6BL, Service Water Building, 4' Elevation, Pipe

Penetration Seal\20-8" Pipe Sleeves Unit 1, SWEL 1 List Unit 1, SWEL 2 List

Unit 2, SWEL 1 List

Unit 2, SWEL 2 List

URS Post Fukushima Project, NTTF Recommendation 2.3 Seismic Walk-down Training Record URS Project Number 30703-007, Near Term Task Force Recommendation 2.3 Seismic Walk-

down Procedure

0PIC-LS001, Omnitrol (Valrec) Level Control Switch Model 613, Single Actuator DBD-106, Hazards Analysis

Engineering Change 80408R0, Flooding Design Basis Update

Individual Plant Examination for Exte

rnal Events Submittal, June 1995 Link Seal Vendor Manual Quick Hit Self-Assessment 541666-15, Emergency Action Level Functionality

SD-43, Service Water System

13 Attachment URS List of Flood Features Inspected URS Near Term Force Recommendations 2.3: Flooding, Project Number 30703-007 Report Number 110311.401, Summary of Progress Energy Fleet Underground Piping and Tanks with the Scope of NEI 09-14 (Rev. 1), prepared by Structural Integrity Associates,

Inc., dated 12/07/2011 Assessment Number 531636, Quick Hit Self Assessment for HNP and BNP Buried Piping Program and the NRC TI-2515/182 Inspection, 08/15/2012 Specification 024-001 for Special Doors

Section 4OA7: Licensee-Identified Violations

Procedures

0PEP-02.1, Initial Emergency Actions 0PEP-02.1.1, Emergency Control - Notification of Unusual Event, Alert, Site Area Emergency, and General Emergency 0PEP-02.2.1, Emergency Action Level Bases

Nuclear Condition Reports

552815 552984

Drawings 1-FP-02039, General Electric Gas Control Piping Diagram

D-02055, Piping Diagram, Carbon Dioxide & Hydrogen Systems, Units 1 & 2

Miscellaneous

Event Notification, Discovery of a Condition that Met the EAL Classification of an Unusual Event (After-the-Fact), August 2, 2012 NUREG-1022, Event Reporting Guidelines Operator Logs, August 2, 2012

SD-59, Hydrogen Water Chemistry System